The U.S. Oil and Gas Industry Can Reduce Pollution, Conserve 

Resources, and Make Money by Preventing Methane Waste

March 2012

Leaking Profits 

Principal Author

Susan Harvey, Harvey Consulting, LLC

Contributing Authors

Vignesh Gowrishankar, Ph.D., Natural Resources Defense Council

Thomas Singer, Ph.D., Natural Resources Defense Council
Acknowledgments

The authors would like to thank the William and Flora Hewlett Foundation for providing funding for this report. We would 

also like to thank the following individuals for their valuable contributions and peer review: Amy Mall, senior policy 

analyst, NRDC; George Peridas, scientist, NRDC Climate Center; Mark Fesmire, Alaska Region director, Bureau of Safety 

and Environmental Enforcement, U.S. Department of the Interior; Geir Vollsaeter, director, Green World Advisors; and Erik 

Schlenker-Goodrich, director of the Southwest Office of Climate and Energy Program, Western Environmental Law Center. 

This report relies heavily on the excellent work of the U.S. Environmental Protection Agency’s Natural Gas STAR Program, 

and the innovative engineering excellence of many oil and gas companies that have developed, tested, and implemented 

new greenhouse gas emission control strategies. Harvey Consulting, LLC. (HCLLC) acknowledges the time, dedication, 

and commitment of the EPA staff to develop and maintain the Natural Gas STAR Program, and the corporations that have 

voluntarily committed to programs to reduce methane emissions.

About the Natural Resources Defense Council

The Natural Resources Defense Council is a national nonprofit environmental organization with more than 1.3 million 

members and online activists. Since 1970, our lawyers, scientists, and other environmental specialists have worked to protect 

the world’s natural resources, public health, and the environment. NRDC has offices in New York City, Washington, D.C., Los 

Angeles, San Francisco, Chicago, Montana, and Beijing.

About Harvey Consulting LLC

Susan Harvey has 25 years of experience as a Petroleum and Environmental Engineer, working on oil and gas exploration 

and development projects. Ms. Harvey is the owner of Harvey Consulting, LLC, a consulting firm providing oil and gas, 

environmental, regulatory compliance advice and training to clients. Ms. Harvey held engineering and management positions 

at both Arco and BP. Ms. Harvey has planned, engineered, executed and managed both onshore and offshore exploration and 

production operations, and has been involved in the drilling, completion, stimulation, testing and oversight of hundreds of wells 

in her career. Ms. Harvey’s experience also includes air and water pollution abatement design and execution, best management 

practices, environmental assessment of oil and gas project impacts, and oil spill prevention and response planning. Ms. Harvey 

taught air pollution control engineering courses at the University of Alaska in the Graduate Engineering Program. 

NRDC Director of Communications: Phil Gutis

NRDC Deputy Director of Communications: Lisa Goffredi

NRDC Publications Director: Alex Kennaugh

NRDC Editor: Jennifer Freeman

Design and Production: Tanja Bos

© Natural Resources Defense Council, 2012

Report available for download at www.nrdc.org/energy/leaking-profits.asp
PAGE 1 | Leaking Profits

Table of Contents

1. Executive Summary......................................................................................................................................... 3

2. Methane Control: Opportunities and Issues.....................................................................................................8

2.1 Incentives to Invest....................................................................................................................................9

2.2 Methane Emission Tracking .......................................................................................................................9

2.3 Uncertainty in Emission Estimates...........................................................................................................12

2.4 Voluntary Control with EPA Natural Gas Star............................................................................................13

3. Analytic Approach...........................................................................................................................................15

3.1 Profitability................................................................................................................................................16

3.2 Examination of Methane Control Options ................................................................................................16

3.3 Methane Emission Reporting Units..........................................................................................................17

4. Ten Profitable Technologies: An Analysis .......................................................................................................18

4.1 Green Completions ..................................................................................................................................18

4.2 Plunger Lift Systems ................................................................................................................................23

4.3 Tri-Ethylene Glycol Dehydrator Emission Controls ...................................................................................26

4.4 Desiccant Dehydrators .............................................................................................................................29

4.5 Dry Seal Systems .....................................................................................................................................30

4.6 Improved Compressor Maintenance........................................................................................................32

4.7 Low-Bleed or No-Bleed Pneumatic Controllers........................................................................................34

4.8 Pipeline Maintenance and Repair.............................................................................................................36

4.9 Vapor Recovery Units ...............................................................................................................................39

4.10 Leak Monitoring and Repair....................................................................................................................42

5. Conclusion and Policy Recommendations......................................................................................................45

Appendix A: Cost-Effectiveness Analysis of Methane Control Technologies.......................................................47

Appendix B: List of Acronyms..............................................................................................................................56

Appendix C: Methane Emission Source Detail.....................................................................................................57

Endnotes ..............................................................................................................................................................59
PAGE 2 | Leaking Profits

FIGURES AND TABLES

Figures

Figure 1: Oil & Gas Production, Processing, Transmission, Refining and 

Distribution Systems Simplified Schematic ................................................. 4

Figure 2: Methane from the O&G Industry as a Pecent of Total U.S. Methane 

Emissions...................................................................................................... 4

Figure 3: O&G Industry Methane Emission Reduction Potential 

by Technology................................................................................................ 6

Figure 4: Current Average Gas Price $4/Mcf................................................ 8

Figure 5: O&G Industry Methane Reduction and Remaining 

Opportunity.................................................................................................... 9

Figure 6: Natural Gas System Methane Emission Sources........................ 10

Figure 7: Liquid Petroleum System Methane Emission Sources................ 10

Figure 8: O&G Industry Methane Emissions 1990-2009 ............................ 13

Figure 9: Payout Period Diagram................................................................. 16

Figure 10: Gas Well Flaring......................................................................... 19

Figure 11: Green Completion Equipment Schematic.................................. 19

Figure 12: Green Completion Equipment.................................................... 20

Figure 13: Green Completion Evaluation Flowchart .................................. 23

Figure 14: Plunger Lift System Schematic.................................................. 24

Figure 15: Plunger Lift System Evaluation Flowchart................................. 25

Figure 16: Glycol Dehydration Unit Schematic........................................... 26

Figure 17: TEG Dehydrator Emission Control Evaluation Flowchart........... 28

Figure: 18 Desiccant Dehydrator Schematic .............................................. 29

Figure 19: Desiccant Dehydrator Evaluation Flowchart ............................. 30

Figure 20: Centrifugal Compressor Leaks Schematic................................. 31

Figure 21: Centrifugal Compressor Dry Seals.................................................31

Figure 22: Wet to Dry Compressor Seal Evaluation Flowchart ......................32

Figure 23: Reciprocating Compressor Rod Packing Leaks Schematic........ 33

Figure 24: Rod Packing Replacement Evaluation Flowchart...........................34

Figure 25: Pneumatic Controller.................................................................. 34

Figure 26: Pneumatic Controller Locations in Natural Gas Production ..........34

Figure 27: Pneumatic Controller Evaluation Flowchart...................................36

Figure 28: Pipeline Hot Tapping Schematic.....................................................36

Figure 29A: Pipeline Pump-Down Technique Using In-Line Compressor 

Schematic.........................................................................................................37

Figure 29B: Pipeline Pump-Down Technique Using Portable Compressor 

Schematic.........................................................................................................37 

Figure 30: Pipeline Maintenance and Repair Evaluation Flowchart ..............38

Figure 31: Vapor Recovery Unit........................................................................39

Figure 32: Vapor Recovery Unit Schematic................................................. 39

Figure 33: Vapor Recovery Unit Evaluation Flowchart................................ 41

Figure 34: Hand Held Infrared Camera............................................................42

Figure 35: Remote Methane Leak Detector ....................................................42

Figure 36: Leaking Valve as shown by Infrared Gas Detecor..................... 42

Figure 37: Leak Monitoring and Repair Evaluation Flowchart.................... 44

Tables

Table 1: Methane Emissions (in Billion Cubic Feet)...................................... 5

Table 2: Methane Emission Sources and Control Technologies................. 11

Table 3: Methane Emission Control Opportunity........................................ 15

Table 4: Methane Capture Technology Costs and Benefits........................ 18

Table 5: Methane Capture Potential from TEG Dehydrator Controls......... 27

Table 6: Crude Oil Tank Vapor Recovery Unit Economics........................... 40

Appendix A

Table A1: Cost-effectiveness of green completions................................... 48

Table A2: Cost-effectiveness of plunger lift systems................................. 49

Table A3: Cost-effectiveness of TEG dehydrator controls.......................... 49

Table A4: Cost-effectiveness of desiccant dehydrators............................. 50

Table A5: Cost-effectiveness of replacing wet seals in 

centrifugal compressors with dry seals...................................................... 50

Table A6: Cost-effectiveness of replacing rod packing in 

reciprocating compressors.......................................................................... 51

Table A7: Cost-effectiveness of replacing high-bleed pneumatic 

controllers with low-bleed pneumatic controllers ..................................... 52

Table A8: Cost-effectiveness of replacing high-bleed pneumatic 

controllers with instrument-air pneumatic controllers............................... 53

Table A9: Cost-effectiveness of installing vapor recovery units................ 54

Table A10: Cost-effectiveness of leak monitoring and repair systems...... 55

Appendix C 

Table C1: Natural Gas System Methane Emission Sources....................... 57

Table C2: Petroleum System Methane Emission Sources.......................... 58
PAGE 3 | Leaking Profits

1. Executive Summary 

Methane is valuable as a fuel, but it is also a greenhouse gas at least 25 times more potent 

than carbon dioxide over a 100 year period, with even greater relative impacts over shorter 

periods. Methane makes up as much as 90 percent of natural gas. Currently the United 

States loses at least 2 to 3 percent of its total natural gas production each year when gas is leaked or 

vented to the atmosphere. Natural gas is routinely allowed to escape into the atmosphere from oil and 

gas industry equipment and processes. This is a waste of a valuable fuel resource as well as a source 

of local pollution and climate change.

A focus on reducing methane waste can produce not only benefits for the climate but also 

substantial profits for oil and gas companies, and revenues for royalty owners including taxpayers, 

who own public lands. This report focuses on 10 profitable and widely applicable methane emission 

reduction opportunities in the United States oil and gas (O&G) industry. If these technologies could 

be used throughout the industry, they have the potential to reduce U.S. methane emissions by 

more than 80 percent of current levels, based on the U.S. Environmental Protection Agency’s (EPA) 

estimates, an amount greater than the annual greenhouse gas emissions from 50 coal fired power 

plants. This methane, if captured and sold, can bring in billions of dollars in revenues while benefiting 

the environment.

A combination of voluntary and mandatory programs implemented by the EPA and many states has 

already reduced the industry’s U.S. methane emissions by more than 20 percent. Given industry 

practice to date, it appears that available control technologies, while profitable, do not provide 

sufficient incentive to drive further voluntary reductions. While voluntary programs have resulted in 

some progress, additional mandatory programs are needed to get closer to the more than 80 percent 

methane reduction level that this report demonstrates could be within our reach.
PAGE 4 | Leaking Profits

The U.S. O&G industry, which includes both liquid petroleum 

(crude oil, condensate, and natural gas liquids) and natural 

gas systems (Figure 1), produced 26,000 Bcf (billion cubic 

feet) of gas in 2009.1

 The industry lost an estimated 623 Bcf of 

methane to the atmosphere in 2009, a loss of 2.4 percent of 

the total U.S. gas produced. This amount of methane, 623 

Bcf, is roughly 37 percent of total U.S. methane emissions 

(Figure 2).2

 Natural gas systems contribute most of the O&G 

industry’s methane emissions, 547 Bcf/year (88 percent of 

the total). Liquid petroleum systems, which currently result 

in methane emissions of about 76 Bcf/year (12 percent of the 

total), represent an additional emission source (Table 1). 

The 10 technologies covered in this report are technically 

proven, commercially available, and profitable ways for 

operators to capture methane that would otherwise be leaked 

or vented to the atmosphere from oil and gas production, 

processing and transportation systems.3 These 10 methane 

control solutions are only a starting point for the O&G 

industry. The EPA’s Natural Gas STAR Program, the O&G 

industry, and equipment vendors have identified nearly 100 

Figure 2: Methane from the O&G Industry as 

a Percent of Total U.S. Methane Emissions 

Total U.S. Greenhouse 

 Gas Emissions

U.S. O&G Industry 

Methane Emissions

Note: Methane made up 10.3 percent of U.S. greenhouse gas emissions in 2009.

Source: U.S. EPA 2011 Greenhouse Gas Inventory

63%

37%

methane control options that have merit.4 We selected these 

10 technologies because they have been proven by the EPA 

and industry to be both profitable and technically feasible, 

time and time again. 

Figure 1: Oil and Gas Production, Processing, Transmission, Refining, and Distribution System 

Simplified Schematic

OIL AND GAS WELLS GAS PROCESSING PLANT COMPRESSOR STATION

OIL REFINERY

OIL AND GAS

SEPARATION

CONSUMER

Gas Production Processing Transmission Distribution

Oil Production Transmission Refining Distribution
PAGE 5 | Leaking Profits

Together, these 10 technologies have the ability to capture 

more than 80 percent of the O&G sector’s methane emissions 

if they could be deployed industry-wide:

1. Green Completions to capture oil and gas well 

emissions 

2. Plunger Lift Systems or other well deliquification 

methods to mitigate gas well emissions

3. Tri-Ethylene Glycol (TEG) Dehydrator Emission 

Controls to capture emissions from dehydrators

4. Desiccant Dehydrators to capture emissions from 

dehydrators

5. Dry Seal Systems to reduce emissions from 

centrifugal compressor seals 

6. Improved Compressor Maintenance to reduce 

emissions from reciprocating compressors 

7. Low-Bleed or No-Bleed Pneumatic Controllers used 

to reduce emissions from control devices 

8. Pipeline Maintenance and Repair to reduce 

emissions from pipelines 

9. Vapor Recovery Units used to reduce emissions 

from storage tanks 

10. Leak Monitoring and Repair to control fugitive 

emissions from valves, flanges, seals, connections 

and other equipment 

Methane control technologies provide economic, health, 

safety, and environmental benefits for both operators and 

the public. These control technologies reduce not only 

greenhouse gas emissions, but also potentially explosive 

vapors, hazardous air pollutants, and volatile organic 

compounds (VOC), improving worker safety and limiting 

corporate liability. Using these technologies, captured 

methane can be turned into a supply of natural gas to meet 

ever-growing market demands, or used as a source of energy 

for operations. When development occurs on public lands, 

use of the technologies can result in royalty payments to the 

government from the sale of captured methane, as well as 

improved stewardship of our natural resources.5

In its 2011 Greenhouse Gas Inventory, the EPA estimated 

that the O&G industry reduced emissions by 168 Bcf in 2009. 

At a price of $4 per thousand standard cubic foot (Mcf), the 

industry generated $672 million in gross revenue by keeping 

this gas in the revenue stream. About a quarter (39 Bcf) of the 

emissions reductions came from Federal regulations such 

as NESHAPs (National Emission Standards for Hazardous 

Air Pollutants), and three quarters (129 Bcf) from voluntary 

emissions reductions under the EPA’s Natural Gas STAR 

program. 

The 10 technologies discussed in this report could 

potentially capture more than 80 percent of the 623 Bcf wasted 

by the O&G industry. Selling this methane at the average 2011 

price of $4/Mcf would generate more than $2 billion annually. 

This is equivalent to reducing greenhouse gas emissions 

from more than:

n	 40,000,000 passenger vehicles

n	 The electric use of 25,000,000 homes

n	 50 coal fired power plants, or

n	 500,000,000 barrels of oil6

Despite these environmental and financial benefits, in some 

instances there are technical, financial and institutional 

barriers that prevent O&G operators or companies from 

voluntarily investing in methane control. Nevertheless, most 

of the methane control technologies highlighted in this 

report can be achieved simply by modernizing outmoded 

business practices, commanding resource and budget 

allocations, and instilling a corporate commitment to 

methane emission reduction. If better operating conditions 

and profits are not enough incentive to implement these 

projects, policies that mandate emissions control will be 

necessary to achieve the full potential of these methane 

control technologies. 

EMISSION REDUCTION POTENTIAL OF

10 Profitable Technologies

Each methane emission control technology evaluated in 

this report contributes to the goal of treating methane as a 

valued resource and keeping it out of the atmosphere. Just 

two methane control technologies, green completions and 

plunger lift systems, can potentially address nearly 40 percent 

of methane emissions (Figure 3). All 10 technologies discussed 

in this report together could address an estimated 88 percent 

of emissions from the O&G industry. This is equivalent to 

reducing gross emissions from 3 percent of production to 

about 0.4 percent of production.

The estimate of potential emissions reductions from 

these ten technologies assumes nearly complete technical 

feasibility for all sources in a category, and sufficient time 

for the deployment of these technologies industry-wide. A 

detailed analysis of the technical feasibility of technology 

deployment is beyond the scope of this report. The estimate 

includes cumulative emissions reductions possible, i.e., not 

incremental to any reductions already made.

Table 1: Methane Emissions (in Billion Cubic Feet)

Natural Gas 

System

Petroleum 

System

O&G

Industry

Gross emissions 715 76 791

Emissions reductions* 168 - 168

Net emissions 547 76 623

*From Natural Gas STAR program and federal regulations

Source: U.S. EPA 2011 Greenhouse Gas Inventory

Only gross emissions estimates are available from the EPA 

in sufficient detail by source to use as a basis for analysis. 

The following emissions estimates, from the EPA’s 2011 

Greenhouse Gas Inventory, are based on gross emissions 

(corresponding to total gross emissions of 791 Bcf/year).7

n	 Green completions, also known as reduced emissions 

completions, are closed loop systems that capture liquids 

and gases coming out of the well during “completions” 

using temporary processing equipment brought to a well 
PAGE 6 | Leaking Profits

site, then routing fluids and gases to a tank for separation 

to enable sale of gas and condensate. Historically, the 

fluids and gases flowing back out of the well have been 

routed to an open air pit or perhaps a tank, allowing 

substantial amounts of methane to vent directly into 

the atmosphere. The EPA estimates that approximately 

8,200 Mcf of natural gas is emitted per well completion, 

on average. Well completions, workovers and cleanups 

emit approximately 305 Bcf gross of methane per year. 

Green completions may be used to control considerable 

emissions from well completions and workovers (68 Bcf). 

Green completions can also be used to control a portion 

of the 237 Bcf/year in emissions from cleanups of low 

pressure wells (also known as liquids unloading). 

n	 Plunger Lift Systems are installed on gas wells that stop 

flowing when liquid (water and condensate) accumulates 

inside the wellbore. These systems lift accumulated 

liquids in the wellbore to the surface. Using this method, 

methane gas can be captured and sold rather than vented 

to atmosphere as waste. Approximately 4,500 to 18,000 

Mcf/year of methane gas is emitted per well, mainly from 

normal cleanup operations. This contributes to the EPA’s 

estimate of total gross emissions of 237 Bcf/year from 

liquids unloading. 

n	 TEG Dehydrator Emission Controls or Desiccant 

Dehydrators can be used to reduce methane waste 

while removing moisture from natural gas from oil or 

gas wells. Methane is often vented during the process 

of dehydrating gas, but it can be captured using either 

emission control equipment placed on TEG dehydrators, 

or with desiccant dehydrators. Desiccant dehydrators 

dry gas by passing it through a bed of sacrificial 

hygroscopic salt (the desiccant); there are no pumps, 

contactors, regenerators, or reboilers. Only a small 

amount of methane is released intermittently when the 

unit is opened to replace the salt. Desiccant dehydrators 

are best suited for low gas flow rates and low gas 

temperatures. Alternatively, where glycol dehydrators are 

still required, there are emission control solutions that 

can capture methane gas for use as fuel. The EPA estimates 

that 20,000 Mcf/year of natural gas is emitted per well 

on average (including both old and new wells), and that 

smaller dehydrators still cumulatively emit approximately 

8 Bcf of methane per year despite mandatory emission 

controls on most large dehydrator systems. A significant 

fraction of this 8 Bcf/year of gross emissions from this 

source can and should be captured.

n	 Dry Seal Systems can be used throughout the O&G 

industry to reduce emissions from centrifugal 

compressors that compress natural gas so that it can 

be efficiently moved through a pipeline. Methane can 

leak from the seals in centrifugal compressors and the 

rod packing mechanisms in reciprocating compressors. 

Installation of improved dry seals in centrifugal 

compressors, and improved compressor maintenance 

by replacing worn rod packing in reciprocating 

compressors, have the potential to significantly reduce 

the amount of methane emitted. The EPA estimates that 

leaking compressors emit about 102 Bcf/year (27 Bcf/

year from centrifugal compressors and 75 Bcf/year from 

reciprocating compressors). A significant fraction of this 

can and should be captured. 

n	 Low-Bleed or No-Bleed Pneumatic Controllers can be 

used throughout the O&G industry to reduce emissions 

while regulating pressure, gas flow, and liquid levels, and 

automatically operating valves. High-bleed pneumatic 

devices are designed to release methane gas to the 

atmosphere. Converting high-bleed gas devices to lowbleed devices, or moving away from gas-operated devices 

altogether in favor of instrument air, reduces methane 

Figure 3: O&G Industry Methane Emission Reduction Potential by Technology

73%

33%

Note: 2009 gross O&G industry methane emission was 791 Bcf. The 10 technologies can address all but 12 percent of these emissions.

Based on data from U.S. EPA 2011 Greenhouse Gas Inventory.

39% Green Completions 

and Plunger Lift Systems

12% Not Addressed 

by 10 Technologies 

18% Leak Monitoring

and Repair

3% Vapor

Recovery Units

2% Pipeline Maintenance

and Repair

13% Low-Bleed or

No-Bleed Pneumatic

Controllers

3% Dry Seal Systems

9% Improved

Compressor Maintenance

1% TEG Dehydrator

Emission Controls and 

Desiccant Dehydrators
PAGE 7 | Leaking Profits

emissions. The EPA estimates that 80 percent of all highbleed pneumatic devices can be retrofitted, and that 

there is an opportunity to reduce a very large fraction 

of the 99 Bcf/year of gross methane emissions from 

pneumatic controllers.

n	 Pipeline Maintenance and Repair can result in methane 

venting to the atmosphere when an oil or gas pipeline is 

cut or when methane is vented to reduce potential fire 

or explosion risk while the pipe is under repair. Instead, 

to mitigate methane release, subject to a thorough safety 

evaluation, gas can either be re-routed and burned as 

fuel during the repair and maintenance, or work can 

be conducted on the pipeline while it is in operation. 

Methane gas venting can also be mitigated by using hot 

tap connections, de-pressuring the pipeline to a nearby 

low pressure fuel system, or using a pipeline pump-down 

technique to route gas to sales. The EPA estimates that 

pipeline maintenance and upset conditions requiring 

venting result in emission of 19 Bcf of methane per year, a 

sizeable fraction of which can and should be captured. 

n	 Tank Vapor Recovery Units (VRUs) capture methane that 

otherwise would escape from crude oil and condensate 

tanks and be vented to the atmosphere through three 

different mechanisms: (1) flashing losses, (2) working 

losses, and (3) standing losses. To reduce these losses, 

a vapor recovery unit can be installed on the tank to 

capture methane gas for sale or for use as fuel. The EPA 

estimates these methane emissions amount to about 21 

Bcf/year, a sizeable fraction of which can and should be 

captured. In addition to methane, tank vapor recovery 

units can also reduce emissions of hazardous air pollutants 

(HAPs), such as benzene, toluene, ethylbenzene, xylenes, 

and volatile organic compounds (VOCs).

n	 Leak Monitoring and Repair prevents leaks at oil or 

natural gas facilities that would otherwise result in 

fugitive methane emissions, which may occur due to 

normal wear and tear, improper or incomplete assembly 

of components, inadequate material specifications, 

manufacturing defects, damage during installation 

or use, corrosion, or fouling. As gas moves through 

equipment under high pressure, methane gas leaks can 

occur from numerous locations at oil and gas facilities: 

valves, drains, pumps, threaded and flanged connections, 

pressure relief devices, open-ended valves and lines, and 

sample points. Because methane is a colorless, odorless 

gas, methane leaks often go unnoticed. Leak monitoring 

programs, and prompt repair when leaks are detected, 

can be effective in controlling fugitive emissions. 

Control can be achieved through a two-part process: 

(1) a monitoring program to identify leaks, and (2) a 

repair program to fix the leaks. The EPA estimates that 

equipment leaks result in gross emissions of 143 Bcf of 

methane per year. A large part of this may be controlled 

by improved leak monitoring and repair programs.

Policy Recommendations

The EPA’s Greenhouse Gas Inventory in recent years represents 

the agency’s best current understanding of methane 

emissions from the O&G industry based on available data, 

recognizing that significant uncertainties exist. Changes 

to the inventory in recent years highlight challenges in 

understanding methane emissions from the O&G industry. 

NRDC calls upon the industry to provide improved data 

to aid the EPA in resolving uncertainties. NRDC strongly 

supports rigorous, mandatory reporting, especially from 

numerous small sources that in aggregate may result in 

significant emissions. Improved data can support more 

robust analyses of methane emissions, which will help 

with the development of appropriate emissions reduction 

solutions.

In its 2011 Greenhouse Gas Inventory, the EPA provides 

an excellent breakdown of emissions by both O&G sector 

(production, processing, transmission) and by source. It does 

not, however, provide enough detail of emissions reduction 

by leakage source. Emissions reduction is only identified 

at a broad sector level. NRDC recommends that the EPA 

provide a more detailed breakdown of emissions reduction 

by leakage source.

On broader policies to control methane emissions, NRDC 

supports the EPA’s steps to improve the O&G industry 

proposed New Source Performance Standards (NSPS) 

to control VOCs,which will achieve significant methane 

reduction co-benefits.8

 For example, methane emitted during 

well completions and recompletions will be controlled to a 

much larger extent once the proposed VOC regulations are 

implemented. The EPA’s proposed NSPS regulations are a 

good starting point.

However, NRDC recommends that the EPA’s proposed 

NSPS regulations go much further.9

 First, the EPA should 

directly regulate methane. In addition, while the EPA has 

proposed federal performance standards for new and 

modified sources, the proposal does not cover the many 

existing sources of methane. The EPA should issue guidelines 

for existing sources, which states would then be required to 

adopt through their State Implementation Plans. The EPA’s 

guidelines should cover all significant sources of emissions, 

and all segments of the natural gas supply chain, and require 

compliance with stronger standards and procedures. 

While the Natural Gas STAR voluntary program has 

achieved some success in controlling methane emissions, 

mandatory control requirements such as under the NSPS and 

NESHAPs programs are necessary for greater industry-wide 

emissions reductions. 

Federal land management agencies should also exercise 

their authority to control methane waste from oil and gas 

lease operations on federal lands.

Finally, state governments also can do more to require 

methane emission controls. Colorado, Montana, and 

Wyoming have rules covering existing methane emission 

sources including wells, pneumatic devices, and storage 

tanks. While these rules provide a good start, they and other 

states should develop even stronger regulations. 
PAGE 8 | Leaking Profits

T

here is well established international scientific consensus, as demonstrated in the findings of 

the Intergovernmental Panel on Climate Change and the National Academy of Sciences, that 

greenhouse gas emissions are a significant cause of climate change.Methane gas is a well 

known and well-documented greenhouse gas, with a much greater global warming potential than 

carbon dioxide on a mass basis. Significant greenhouse gas emission controls, and methane emission 

control in particular, help to mitigate global warming.

2. METHANE CONTROL: OPPORTUNITIES AND ISSUES

Methane is the primary component of natural gas, which 

typically contains 80 to 90 percent methane, ranging up 

to as high as 98 percent in some cases.10 Every standard 

cubic foot (scf) of methane gas lost to the atmosphere is a 

standard cubic foot of methane not sold—a direct, real, and 

measurable loss of revenue. Methane control ensures that the 

gas produced at the well is kept in the revenue stream.11

Not only are methane capture projects in the O&G industry 

critical for addressing the climate crisis, but such projects 

also can be profitable, improve safety, maximize energy 

resources, reduce economic waste, protect human health, 

and reduce environmental impacts. Furthermore, upgrading 

production assets with modern and efficient equipment 

has improved operational and economic performance, 

making assets more robust and less susceptible to upsets and 

downtime.

Using a gas price of $4/Mcf, based on average 2011 prices, 

every Bcf of methane captured and sold, rather than vented 

into the atmosphere, can generate approximately $4 million in 

gross revenue. The EPA used $4/Mcf as a conservative estimate 

in its 2011 NSPS proposed rulemaking (Figure 4). Many of 

the control technologies pay out their investment and start 

generating profits after a short period of time for the O&G 

industry, as well as those, including the U.S. government, who 

receive royalties and taxes on gas sales. 

Figure 4: Current Average Gas Price $4 Per Methane Cubic Square Feet

Henry Hub Natural Gas Price

0 

2 

4 

6 

8 

10 

Jan 2011 Jul 2011 Jan 2012 Jul 2012 Jan 2013 Jul 2013 

Note: Confidence interval derived from options market information for the 5 trading days ending March 1, 2012

Intervals not calculated for months with sparse trading in "near-the-money" options contracts 

dollars per million Btu 

Source: U.S. Energy Information Administration, Short-Term Energy Outlook, March 2012 

Historical spot price 

STEO price forecast 

NYMEX futures price 

95% NYMEX futures price upper confidence interval 

95% NYMEX futures price lower confidence interval 
PAGE 9 | Leaking Profits

2.1 Incentives to Invest

In light of the fact that methane controls have been shown to 

be profitable, a commonly asked question is: “Why doesn’t the 

O&G industry voluntarily invest in methane emission control?”

In some limited cases, site-specific factors, such as flow 

rate, temperature, and low gas pressure, make methane 

emissions control technically infeasible or unprofitable. 

However, for most of the methane control technologies 

highlighted in this report, it is simply a matter of modernizing 

outmoded business practices, commanding resource and 

budget allocations, and instilling a corporate commitment to 

greenhouse gas emission reduction. 

The American Petroleum Institute (API) explains that in 

order to maximize profit and provide shareholders with the 

highest possible return on investment, the O&G industry 

operates with a strict ranking of capital projects for maximum 

yield.12 Thus, even though methane control can be profitable, 

other core business projects with an even higher rate of 

return often compete successfully for available corporate 

funding. Payout periods for methane control technologies 

discussed in this report range from immediate to three years, 

yet this may not be attractive enough to compare with oil 

and gas companies’ high expected rates of return. In other 

cases, factors such as reserves booking (accounting for oil 

and assets on the balance sheet), and short- and long-term 

acquisition and divestment strategies can outweigh even high 

return, low capital methane reduction projects. 

Obstacles to implementing even profitable methane 

control technologies—whether site-specific, financial, or 

institutional arising from company culture—may seem 

hard to overcome. But there is an especially compelling 

case for fixing market failures where limiting greenhouse 

gas emissions and profits go hand in hand. This is why 

NRDC finds that where companies do not adopt these 

technologies voluntarily, regulations requiring mandatory 

reductions should be implemented. For companies that 

lack the technical expertise or staff resources in house, there 

are excellent private and federal resources for technical 

assistance on methane control. 

2.2 Methane Emission Tracking 

In its 2011 Greenhouse Gas Inventory, the EPA estimated that 

the O&G sector emitted 623 Bcf of methane, with natural gas 

systems accounting for 547 Bcf and liquid petroleum systems 

contributing 76 Bcf. The EPA also estimated that the industry 

captured 168 Bcf of gross methane emissions in 2009, 

exclusively from natural gas systems.13 If no reductions were 

implemented, the gross leak rate would be an estimated 791 

Bcf/year (623 Bcf/year net emissions plus 168 Bcf/year) as 

shown in Figure 5. The United States produces approximately 

26,000 Bcf of natural gas per year. Thus, at the gross leak rate 

of 791 Bcf/year, the U.S. O&G industry is losing 3 percent of 

its total gas production to the atmosphere. At the EPA’s net 

leak rate of 623 Bcf/year , the industry is losing 2.4 percent of 

its total gas to the atmosphere. 

As discussed in Section 2.3 below, the EPA numbers are 

quite uncertain. Other sources indicate that the amount 

of methane lost to the atmosphere each year in the United 

States could be substantially higher.14

According to the 2011 Greenhouse Gas Inventory, industry 

achieved the 168 Bcf in reductions through a combination of 

the EPA’s successful voluntary emission reduction program, 

Natural Gas STAR (77 percent), and federal emission 

regulations imposed on industry in the past decade to 

curb emissions (23 percent). The EPA did not identify any 

emission reductions achieved in the petroleum systems 

category. Most oil production operations also produce 

associated gas. Based on EPA estimates, there is a 76 Bcf 

methane reduction opportunity for the petroleum systems 

category.

The 2011 Greenhouse Gas Inventory tracks methane 

emissions by leakage source for natural gas systems (Figure 

6) and liquid petroleum systems (Figure 7). In natural gas 

systems, methane emissions primarily come from wells, 

pneumatic controllers, compressors, and fugitive emissions. 

In liquid petroleum systems, methane emissions primarily 

come from equipment leaks, pneumatic controllers, and 

tank venting. Table 2 shows natural gas and liquid petroleum 

methane emissions in Bcf and identifies the applicable 

methane control technologies covered in this report.

A detailed breakdown of the methane emissions from both 

natural gas and liquid petroleum systems by source is shown 

in Appendix C.

Figure 5: O&G Industry Methane Reduction and Remaining Opportunity

168 Bcf/yr reductions already made

623 Bcf/yr remains to be captured

former 1.3

Source: U.S. EPA 2011 Greenhouse Gas Inventory

79%

21%
PAGE 10 | Leaking Profits

Figure 6: Natural Gas System Methane Emission Sources

73%

33%

Note: 2009 total emissions 715 Bcf

9% Well Completions 

and Workovers

33% Well Clean Ups

(Low pressure gas wells)

1% Dehydrator Vents

4% Centrifugal 

Compressors Wet Seals 11% Reciprocating Compressors

Other Sources 12% 

Pneumatic 11%

Controllers 

Pipeline Emissions 3%

 

Tank Venting 1%

 

Fugitive Emissions 15% 

Source: U.S. EPA 2011 Greenhouse Gas Inventory

Figure 7: Liquid Petroleum System Methane Emission Sources

73% 49% Fugitive Emissions 

2% Refining 

Pneumatic 29%

Controllers

Combustion and 6% 

Process Upsets 

Tank Venting 14% 

Note: 2009 total emissions 76 Bcf

Source: U.S. EPA 2011 Greenhouse Gas Inventory
PAGE 11 | Leaking Profits

Table 2: Methane Emission Sources and Control Technologies

2009 Natural Gas Systems % of Total Control Technologies

Bcf %

Well Completions and Workovers 68 9% No. 1 Green Completions

Well Clean Ups (Low pressure gas wells) 237 33% No. 1 & 2 Green Completions & Plunger 

 Lift Systems or Other Deliquification Methods

Dehydrator Vents 8 1% No. 3 & 4 Dehydrator Controls

Centrifugal Compressors Wet Seals 27 4% No. 5 Dry Seal Systems

Reciprocating Compressors 75 11% No. 6 Improved Compressor Maintenance

Pneumatic Controllers 77 11% No. 7 Low -Bleed or No-Bleed Controllers

Pipeline Emissions 19 3% No. 8 Pipeline Maintenance and Repair

Tank Venting 10 1% No. 9 Vapor Recovery Units

Fugitive Emissions 106 15% No. 10 Leak Monitoring and Repair 

Total of Emissions Controllable by the 

10 Technologies 627 88%

Other Sources 88 12%

Total Emissions - Natural Gas 715 100%

2009 Liquid Petroleum Systems % of Total Control Technologies

Bcf %

Pneumatic Controllers 22 29% No. 7 Low-Bleed or No-Bleed Controllers

Tank Venting 11 14% No. 9 Vapor Recovery Units

Fugitive Emissions 37 49% No. 10 Leak Monitoring and Repair

Total of Emissions Controllable by the 

10 Technologies 70 92%

Other Sources 6 8%

Total Emissions - Liquid Petroleum 76 100%

Source: U.S. Environmental Protection Agency Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2009.
PAGE 12 | Leaking Profits

2.3 Uncertainty in Emission Estimates

The EPA has been tracking methane emissions since 

1990. For more than 20 years, significant uncertainty 

has accompanied estimates of emissions from the O&G 

industry, with a general theme of underestimation. Some 

emissions have been underestimated by and for the O&G 

industry because sources have not been metered or tested 

to accurately determine the emission rate. Small emission 

sources that may result in cumulatively large emission totals 

have escaped emission monitoring or reporting, and not all 

emission sources are accounted for. 

Evidence for underestimation due to uncertainty is found 

in the 2010 Greenhouse Gas Inventory, which 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.”15

Historically, the Greenhouse Gas Inventory was based on an 

emission factor of approximately 3,000 standard cubic feet 

(3 Mcf) per gas well drilled and completed.16 Yet Natural Gas 

STAR program partner experience shows several cases where 

emission factors were thousands of times higher:

n	 BP employed green completions at 106 wells and 

reported 3,300 Mcf of gas recovered per well17

n	 Devon Barnett Shale employed green completions at 

1,798 wells between 2005 and 2008 and reported 6,300 

Mcf of gas recovery per well18

n	 Williams employed green completions at 1,064 wells 

in the Piceance Basin and reported 23,000 Mcf of gas 

recovered per well19

All of these examples show gas recovery estimates more than 

1,000 times higher than the 3 Mcf of gas per well estimated 

in the 2008 Greenhouse Gas Inventory.

20 Clearly, errors in 

emission inventory estimations have occurred. 

Well completion emission estimates were 

underestimated by a factor of 1,000

The source of much of this uncertainty regarding well venting 

is the EPA’s historic reliance on a 1997 study jointly funded 

with the Gas Research Institute (GRI) to quantify methane 

emissions from United States natural gas operations.21 The 

study concluded that methane emitted (leaked and vented) 

from natural gas facilities at an amount of 1.4 percent +/- 0.5 

percent (approximately 1 to 2 percent) of gross natural gas 

production, and that additional emission controls could 

significantly reduce the amount of methane gas leaked and 

vented to atmosphere. 

However, the study did not include important equipment 

leaks and venting that took place at the wellhead or at the 

well pad processing facilities in natural gas systems. 

The largest change in methane emission estimates has 

been in accounting for wellhead and well pad processing 

facilities emissions that were substantially underestimated. 

Since 1990, the EPA has more than doubled its methane 

emission estimate for natural gas systems from 220 Bcf to 

464 Bcf. For many years the EPA quoted a 300 to 400 Bcf/

year methane emission estimate for the entire O&G industry, 

yet now the EPA reports a 322 to 464 Bcf range for natural 

gas production alone (Figure 8). While some of the methane 

emission increase is attributed to growth in natural gas 

production, most of the increase represents continuous 

improvement in and revisions to the EPA’s emission estimates 

as it furthers its understanding of methane emissions 

sources from the O&G industry. For instance, in past years 

emissions arising from poor connections from the wellhead 

to processing equipment to transmission equipment were 

overlooked. Low emissions from the distribution stage as a 

result of low-leakage welded joints may have contributed to a 

misconception that equipment upstream of the distribution 

stage was also similarly leak-free. 

In 2010, the EPA undertook to develop a set of greenhouse 

gas reporting requirements for the O&G industry as part 

of a general charge from Congress to develop greenhouse 

gas reporting rules for all U.S. industries. The EPA assessed 

uncertainty in O&G emission estimates during this 

undertaking. The EPA explained the historic underestimation 

of natural gas systems, critiquing the “outdated and 

potentially understated” emissions estimates from the 

1997 report. 22 The EPA cited several significant sources of 

underestimated emissions: 

The following emissions sources are believed to be 

significantly underestimated in the United States 

GHG Inventory: well venting for liquids unloading; 

gas well venting during well completions; gas 

well venting during well workovers; crude oil and 

condensate storage tanks; centrifugal compressor 

wet seal degassing venting; and flaring.

In its 2011 Greenhouse Gas Inventory, the EPA raised its gross 

emissions estimate to 791 Bcf/year by adding the amount 

of gas that may be vented at the wellhead to the amount of 

gas that leaks from the processing equipment and pipeline 

infrastructure once the gas enters the system.

According to the EPA’s O&G Reporting Rule Technical 

Support Document, the emissions estimates for these sources 

“do not correctly reflect the operational practices of today.” In 

fact, the EPA believes that “emissions from some sources may 

be much higher than currently reported in the United States 

GHG Inventory.”23

The EPA revised emissions factors for four of these 

underestimated sources. Revised emissions estimates range 

from 11 times higher for well venting from liquids unloading, 

to 36 times higher for gas well venting from conventional 

well completions, to 3,540 and 8,800 times higher for gas 

well venting during well workovers and completions of 

unconventional wells, respectively.24 Even with the EPA’s 

revisions to the O&G Reporting Rule, uncertainty continues 

to exist in the estimates of emissions from gas well 

completions and well workovers. As the EPA noted in the 

preamble to its proposed reporting rule:
PAGE 13 | Leaking Profits

Figure 8: O&G Industry Methane Emissions 1990 to 2009 

73%

0 

50 

100 

150 

200 

250 

300 

350 

400 

450 

500 

1990 1995 2000 2005 2009 

Natural Gas Systems - 

Production 

Natural Gas Systems - 

Processing 

Natural Gas Systems - 

Transmission 

Natural Gas Systems - 

Distribution 

Liquid Petroleum

Systems - Distribution 

 Methane Bcf

Source: U.S. EPA 2011 Greenhouse Gas Inventory

“[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.” 25

The EPA continues to report substantial uncertainty in its 

overall greenhouse gas emission estimates in its ongoing 

work on the Greenhouse Gas Inventory,

26 with uncertainty 

particularly evident for natural gas systems. In its 2011 

Greenhouse Gas Inventory, the EPA used an average emission 

factor of 7,700 Mcf per well completion—much higher 

than its previous emissions factor of 3,000 Mcf per well 

completion—more than doubling the amount of emissions 

expected from the increasing number of unconventional 

well completions (e.g. horizontal and shale gas wells). 

Furthermore, the EPA did not include emissions from 

completions for tight gas wells in the 2011 Greenhouse Gas 

Inventory, which, as the EPA noted previously in its O&G 

Reporting Rule Technical Support Document, is a “significant 

underestimate” of total emissions.27 The EPA also reported 

zero emissions from well completions in the Northeast 

region, which is the location of extensive shale gas drilling 

and well completions in the Marcellus Shale. 

Emissions estimates will likely continue to evolve and 

improve as the EPA obtains additional information from 

the O&G industry, including information submitted under 

its mandatory reporting rule. As with past inventories, it is 

expected that both emissions factors and activity factors will 

continue to be updated. If past trends hold, these factors 

are likely to be revised upward as a result of both better 

understanding of emissions associated with each process, 

and the aggressive pace of drilling and development across 

the country. However, emissions estimates for an individual 

source may also be revised downward as the EPA obtains 

better information about the type and amount of control 

technology in use.

Incidentally, the United States is not the only country that 

has struggled with estimating the O&G industry’s greenhouse 

gas emissions. Canada reports that its natural gas processing 

plants also discovered that methane emissions were roughly 

an order of magnitude higher than estimated.28

Despite all the uncertainty about the precise amount of 

methane emissions, we do know that there is a significant 

amount of methane that is leaking or being vented into the 

atmosphere that could be captured and sold or used as fuel. 

2.4 Voluntary Control

with EPA Natural Gas STAR

For a number of years, the EPA has coordinated the Natural 

Gas STAR Program, which describes itself as a “flexible, 

voluntary partnership that encourages oil and natural gas 
PAGE 14 | Leaking Profits

companies—both domestically and abroad—to adopt costeffective technologies and practices that improve operational 

efficiency and reduce emissions of methane, a potent 

greenhouse gas and an important transitional energy source.”29

To its credit, the EPA actively encourages O&G operators to 

invest in methane reduction technology through its Natural 

Gas STAR Program. Those members of the O&G industry that 

have recognized the adverse economic and environmental 

implications of methane emissions, and have voluntarily 

invested in greenhouse gas emission reduction technology at 

their facilities, also deserve credit. 

While the Natural Gas STAR Program has been successful 

in identifying and documenting profitable methane emission 

reduction opportunities that aid in methane capture and in 

bringing captured methane into the revenue stream, to date 

the program remains voluntary and participation is limited. 

Companies that participate in Natural Gas STAR sign a 

Memorandum of Understanding with the EPA, then evaluate 

and implement identified methane emission reduction 

opportunities. Companies can participate at any level they 

choose, from company-wide to site-specific to small pilot 

projects.30 There is no mandatory requirement to identify or 

implement all methane reduction opportunities. 

The extent to which enrolled companies participate 

is difficult to confirm. Natural Gas STAR publishes a list 

of participating companies, but all reports on the actual 

locations of emission control implementation, which 

methane control measures have been implemented by 

each company, and the emission reductions achieved, are 

confidential. 

Despite these demonstrated solutions for capturing 

methane, many companies still have not participated in 

the Natural Gas STAR Program at all, and others have only 

implemented a few methane control measures.31 Effective as 

the EPA’s Natural Gas STAR efforts have been, vast quantities 

of methane continue to leak into the atmosphere. It is 

therefore clear that voluntary measures alone will not ensure 

that industry installs even profitable capture technologies. 

2.5 Proposed EPA Rules 

Not Strong Enough

On August 23rd 2011, the EPA published proposed regulations 

for a suite of technologies to reduce harmful air pollution from 

the oil and natural gas industry.32 The rules are to be finalized 

by April 2012, after an opportunity for public comment. 

The proposed EPA rules include NSPS for source categories 

as well as air toxics standards, or NESHAPs. In particular, the 

EPA is proposing stringent new NSPS for controls for VOCs 

from the oil and gas sector, which will also capture significant 

amounts of methane (referred to as “co-benefits” of the 

regulation). 

The EPA estimates that the proposed NSPS for VOCs would 

reduce 540,000 tons of VOCs, an industry-wide reduction of 

25 percent. The air toxics standards would reduce air toxics 

emissions by 30,000 tons, an overall reduction of nearly 30 

percent.33 The EPA estimates that the proposed standards 

would also reduce about 3.4 million tons per year of methane. 

This equates to roughly 160 Bcf/year. As an interim measure, 

the EPA quantified the global social benefits of these methane 

reductions in mitigating climate change at up to $4.7 

billion in 2015 co-benefits. For reasons set forth in NRDC’s 

comments to the EPA on the proposed NSPS, we believe even 

this figure is a substantial underestimation.

Finally, the emissions baseline used in the EPA’s proposed 

NSPS differs somewhat from the 791 Bcf/year gross 

emissions baseline in this report derived from the EPA’s 2011 

Greenhouse Gas Inventory. The differences reflect, among 

other things, the evolving nature of the emissions inventory. 

However, the differences do not meaningfully alter the 

analysis and recommendations made in this report.

The EPA’s proposed standards do not control methane 

directly or cover existing sources, which account for the 

bulk of VOC and methane emissions. Further, the EPA omits 

other significant sources of VOCs and methane, in part due 

to exclusion of these sources altogether and in part because 

methane is not directly regulated. These omissions contrast 

with areas where the NSPS would in fact more effectively 

control emissions, such as from well completions and 

recompletions, and new sources of emission from pneumatic 

controllers, compressors, and equipment leaks.

This report does not provide a comprehensive assessment 

of the proposed NSPS, but the control technologies described 

here can serve as a guide to the EPA and the states in their 

control efforts. 

Methane emissions reductions should be a high priority, 

as they provide economic, health, safety, and environmental 

benefits for both operators and the public. Existing market 

forces, government regulations, and voluntary programs are 

only leading to the capture of a small percentage of methane 

emissions at present. The EPA’s proposed NSPS is a step in the 

right direction.
PAGE 15 | Leaking Profits

3. Analytic Approach

While it would have been useful for the EPA to report the 168 Bcf emission reductions by 

leakage source, to clarify which sources and associated emissions reduction technologies 

are making progress in reducing emissions, that level of detail is not necessary to analyze 

the data and describe in layman’s terms why methane control technologies are profitable and point out 

large potential methane control opportunities.

Since the EPA does not provide sufficient data in its inventory 

to break down the emission reductions by natural gas leakage 

source, the methane emission estimates used in this report 

correspond to EPA’s emission estimate of 791 Bcf for natural 

gas and liquid petroleum systems. 

This 791 Bcf estimate of gross emissions from both natural 

gas (715 Bcf) and petroleum (76 Bcf) systems has been 

reduced, the EPA reports, by 168 Bcf from Natural Gas STAR 

programs and regulations. All of these reductions have been 

achieved in natural gas systems. The total net emissions 

from both systems is therefore 623 Bcf (791 Bcf less 168 Bcf). 

The total net emissions from natural gas systems is 547 Bcf 

(715 Bcf less 168 Bcf), and from petroleum systems it is 76 Bcf 

(Table 3). Additionally, it is important to note that the EPA’s 

Natural Gas STAR Program emission reduction estimates are 

based on data voluntarily submitted by industry. These data 

represent a very rough estimate of the amount of methane 

control that may have been achieved to date, because they 

were not developed using common and rigorous metering, 

measurement, quality control, or audit procedures. Therefore, 

some caution should be exercised in assuming that this 

amount of emissions reduction has been fully achieved. 

Table 3: Methane Emission Control Opportunity

2009 Natural Gas Systems 

Natural 

Gas STAR

Reductions

EPA

Regulation 

Reductions

Total 

Reductions 

Estimated 

Remaining 

Target

Gg Bcf Bcf Bcf Bcf Bcf

Production 8,931 464 104 38 142 322

Processing 931 48 4 1 5 43

Transmission 2,482 129 19 0 19 110

Distribution 1,422 74 2 0 2 72

Total 13,766 715 129 39 168 547

2009 Liquid Petroleum Systems

Production 1,444 75 0 0 0 75

Transmission 5 0 0 0 0 0

Refining 24 1 0 0 0 1

Total 1,473 76 0 0 0 76

Source: U.S. EPA 2011 Greenhouse Gas Inventory 

*Slight rounding error accumulated in EPA tables. EPA records 715 Bcf and 168 Bcf as final estimates for 2009. Conversion: Gg/19.26=Bcf 

 
PAGE 16 | Leaking Profits

3.1 Profitability

Profitable emission control opportunity, for purposes of this 

report, means an investment in methane emission control 

technology that results in more revenue generated or costs 

offset than the cost to install, operate, and maintain the 

emission control technology. To assist in identification of 

such opportunities, this analysis used the following criteria: 

1. Control technology that either allows methane to be 

captured and placed into a natural gas pipeline for sale, 

or captured and used as fuel to offset operating cost

2. Technology that is commercially available, meaning 

that it has been developed, tested, and is available in the 

market for purchase and installation

3. Technology that has been used successfully in actual 

O&G operations

4. Emission control solutions that are well documented and 

reported by the O&G industry as profitable

The analysis recognizes that some emission reduction 

measures can be implemented quickly, while others 

may require more extensive planning, procurement, and 

execution timing. 

Most of the emission control technologies described in 

this report have a very short payout period of a few months 

or years. The term “payout” means the period of time 

that it takes for the net cash flow to equal the investment 

expenditure, at which point the investment breaks even and 

starts to generate positive cash flow, as shown in Figure 9.34

The revenue stream is calculated using constant dollars over 

the payout period.35

3.2 Examination of Methane 

Control Options

Each of the 10 methane control options examined in this 

report is considered with a six-part analysis.

1. Technology Description. The technology description 

section identifies the equipment required and processes 

used in each control technology to capture methane 

emissions. 

2. Opportunity. The opportunity section identifies the gross 

amount of methane emissions in the 2011 Greenhouse 

Gas Inventory that could be captured by each control 

technology for its associated leakage source. 

This estimate of potential emissions reductions 

assumes nearly complete technical feasibility for 

all sources in a category, and sufficient time for the 

deployment of these technologies industry-wide. A 

detailed analysis of the technical feasibility of technology 

deployment is beyond the scope of this report. As 

such, the per-unit emission estimates provided in the 

opportunity section of the report are intended to provide 

an average emission control number, to use as a starting 

basis in a feasibility assessment. Individual consideration 

may be appropriate based on unique or exceptional 

circumstances at each site.

3. EPA Proposed Regulations. This section analyzes the 

proposed regulations from the EPA that are relevant 

to emissions from each source. It also discusses the 

emission reductions anticipated from the proposed EPA 

regulations, and concludes with a description of possible 

shortcomings of and improvements to the EPA proposal. 

4. Profit. The profit section analyzes the costs of 

implementing each technology, along with any 

associated operational savings and revenues from 

methane sales. The revenues are calculated by 

multiplying the amount of methane controlled by a price 

of $4/Mcf. The report does not attempt to quantify the 

additional financial benefits from offsetting fuel costs. 

Comparing the costs with the savings and additional 

revenues provides the profit. The average payout period 

is also calculated using these numbers. The cost data are 

intended to provide an average cost to use as a starting 

basis in a feasibility assessment. Again, individual 

consideration may be appropriate based on the 

particulars of a given application. 

 The proposed EPA regulations provide some 

estimates of the profitability of the various control 

technologies. However, in the supporting documentation 

for the proposed rulemaking, the EPA was not transparent 

enough about its methodology for cost-benefit estimates.36

As a result, we were unable to independently verify 

sources and incorporate them into profitability estimates. 

Instead, we have relied on estimates from prior EPA and 

company reports. For the sake of completeness, in the 

appendix we provide tables of profitability estimates by 

control technology from this report, and compare them 

with the EPA estimates from the proposed rulemaking 

supporting documentation. In general, the EPA’s 

proposed rulemaking estimates are somewhat more 

conservative than NRDC estimates. A more detailed 

analysis of NRDC’s profitability comparisons can be 

found in the EPA’s rulemaking docket.37

Total Net Profit 

Initial Investment 

+ 

0 

- 

Payout

Period 

Time 

Cumulative Net Cash Position

Figure 9: Payout Period Diagram
PAGE 17 | Leaking Profits

5. Additional Benefits. Beyond generating revenue, 

the additional benefits of methane capture for each 

technology are highlighted in this section.

6. Limitations and Evaluation. All emission control 

options have some technological (and, potentially, 

economic) limitations, and where those are known, 

they are summarized in this section for use as a starting 

point in a feasibility assessment. In some cases, a certain 

emission control technology may not be suitable because 

it cannot handle a gas flow rate, temperature, or pressure. 

In other cases, the technology may not be appropriate 

for a retrofit, but would be a logical choice for designing 

and installing a new unit. This section includes flow 

charts to depict the basic decision steps of a feasibility 

analysis. The flow charts are intended to be simplistic 

outlines of the steps that might be taken to determine 

the feasibility of using a particular emission control 

method. This simplified approach is not intended to 

replace any company-specific evaluation processes, but 

rather to provide a basic outline of the evaluation steps 

in laymen’s terms. 

3.3. Methane Emission Reporting Units

While greenhouse gas emission estimates are often reported 

in terms of million metric tons of carbon dioxide equivalent 

(MMtCO2

e), all methane emission and methane control 

estimates in this report are shown in terms of standard cubic 

feet, and most often reported in billions of standard cubic 

feet (Bcf). The report uses this emission reporting convention 

because gas is sold and used on a basis of standard cubic feet, 

and this unit can readily be converted to a profit estimate 

using a market price assumption of four dollars per thousand 

standard cubic feet ($4/Mcf). This reporting convention 

prevents the reader from having to routinely convert from 

MMtCO2

e to Bcf. 
PAGE 18 | Leaking Profits

4. TEN PROFITABLE TECHNOLOGIES: AN ANALYSIS

Table 4: Methane Capture Technology Costs and Benefits

Technology Investment Cost Methane Capture Profit Payout

Green Completions $8,700 to $33,000 per well 7,000 to 23,000 Mcf/well $28,000 to $90,000 per well < 0.5 – 1 year

Plunger Lift Systems $2,600 to $13,000 per well 600 to 18,250 Mcf/year $2,000 to $103,000 per year < 1 year

TEG Dehydrator Emission 

Controls Up to $13,000 for 4 controls 3,600 to 35,000 Mcf/year $14,000 to $138,000 per year < 0.5 years

Desiccant Dehydrators $16,000 per device 1,000 Mcf/year $6,000 per year < 3 years

Dry Seal Systems $90,000 to $324,000 per device 18,000 to 100,000 Mcf/year $280,000 to $520,000 per year 0.5 – 1.5 years

Improved Compressor 

Maintenance $1,200 to $1,600 per rod packing 850 Mcf/year per rod packing $3,500 per year 0.5 years

Pneumatic Controllers

 Low-Bleed $175 to $350 per device 125 to 300 Mcf/year $500 to $1,900 per year < 0.5 – 1 year

Pneumatic Controllers

 No-Bleed $10,000 to $60,000 per device 5,400 to 20,000 Mcf/year $14,000 to $62,000 per year < 2 years

Pipeline Maintenance 

and Repair Varies widely Varies widely but significant Varies widely by significant < 1 year

Vapor Recovery Units $36,000 to $104,000 per device 5,000 to 91,000 Mcf/year $4,000 to $348,000 per year 0.5 – 3 years

Leak Monitoring and Repair $26,000 to $59,000 per facility 30,000 to 87,000 Mcf/year $117,000 to $314,000 per 

facility per year < 0.5 years

Note: Profit includes revenue from deployment of technology plus any O&M savings or costs, but excludes depreciation. Additional details provided in Appendix A.

Source: NRDC analysis of available industry information. Individual technology information sources cited in Chapter 4.

T

he emission control potential, uses, benefits, and economics of each of the 10 methane control 

technologies are discussed in greater detail in this chapter. While many of the technologies are 

profitable on a very short time scale, many operators still have not installed them. In order to 

realize the methane control potential to limit greenhouse gas emissions, NRDC also proposes policy 

options to encourage the use of these technologies. 

4.1 Green Completions

Methane gas is often released into the atmosphere 

when natural gas or oil wells are drilled, stimulated (e.g. 

hydraulically fractured), or repaired. Green completions 

can be used to capture methane gas and gas liquids 

(condensate).38 Rather than being vented or flared into the 

atmosphere, methane captured in a green completion can be 

sold, used as fuel, or re-injected to improve well performance. 

Green completions also capture gas liquids that can be sold. 

This technology is also called reduced emission completions, 

or REC, but throughout this report we use the term “green 

completions.”

When a well is drilled and completed, stimulated, or 

repaired, it is standard procedure to flow the well for 

a period of time to remove stimulation materials and 

other debris from the wellbore. This procedure is called 

“wellbore cleanup” and occurs before connecting the well to 

permanent processing equipment. Wellbore cleanup allows 

the operator to remove and dispose of unwanted material 
PAGE 19 | Leaking Profits

without contaminating production facilities and pipelines. 

It also improves well recovery rates by reducing wellbore 

formation damage downhole. Historically, wells were 

“cleaned up” by flowing liquid hydrocarbons to an open pit or 

tank, and by routing the associated methane gas to a gas vent 

or flare (Figure 10). 

Venting gas near well operations creates potentially 

explosive vapor levels and can pose a human health hazard. 

Flaring resolves much of the explosive vapor problem by 

routing gas away from the well operations to a flare stack 

that burns the gas at a distance from the well and associated 

facilities, but flaring creates economic waste by combusting 

gas that could otherwise be collected and sold. Flaring also 

varies in efficiency, so not all pollutants may be combusted, 

and also generates air, light, and noise pollution.

4.1.1 Technology Description 

In a green completion, the operator brings temporary 

processing equipment to a well site during wellbore cleanup. 

Well cleanup fluids and gases are routed to the temporary 

processing equipment. Fluids, debris, and gas are separated, 

and gas and condensate are recovered for sale. The temporary 

processing equipment required for a green completion 

typically includes gas-liquid-sand separator traps, portable 

separators, portable gas dehydration units, additional tanks, 

and, sometimes, small compressors. A simplified schematic 

showing the equipment required for a green completion is 

shown in Figure 11.

Green completion processing equipment, which provides 

temporary gas processing capability, is typically mounted 

on a truck or trailer to move it from well to well (Figure 12). 

Figure 10: Gas Well Flaring

Figure 11: Green Completion Equipment Schematic 

Sand 

Trap

Wastewater 

Tank

Condensate

Tank

Wellhead

Separator

Separator

Gas 

Dehydrator

© Robert Donnan
PAGE 20 | Leaking Profits

Portable green completion units are either owned by the 

operator or rented from a service provider. For new wells, 

equipment may need to be brought to the well site to provide 

temporary gas processing capability. However, at existing 

well sites, where wells have already been drilled but may 

need to be repaired or stimulated to improve hydrocarbon 

production rates, gas processing equipment may already be 

available onsite. 

While the processing equipment is portable, some 

permanent facility infrastructure must be in place at the 

well site to make a green completion possible. Gas collected 

from a green completion can be used in several ways. It can 

be sold in a pipeline, used as fuel at the well site, or used as 

gas lift to enhance hydrocarbon production in low pressure 

wells. Each of these uses requires piping infrastructure to be 

in place at the well site to route the gas to the appropriate 

destination. Therefore, a green completion is typically not an 

option for exploration wells with no offset wells or pipeline 

infrastructure nearby. 

The EPA estimates that an average of 8,200 

Mcf can be recovered per green completion

Typically, gas produced from a well contains liquid (“wet 

gas”) that exceeds the acceptable moisture content allowed 

in a gas sales pipeline. Depending on the gas composition, 

hydrocarbons may also condense from a gas to a liquid 

under certain temperature and pressure conditions. The 

pressure drop from the wellhead through the gas processing 

equipment can also yield gas-liquids (condensate) that 

can be captured and sold. Therefore, in most cases, before 

gas from a green completion can be routed to a gas sales 

pipeline, it must be dehydrated to remove liquids to meet 

the gas pipeline specifications. Gas dehydration can be 

accomplished by bringing in a portable gas dehydration unit, 

or using a permanent gas dehydrator installed upstream 

of a gas pipeline. Condensate can either be collected in a 

temporary stock tank, or routed to a permanent stock tank if 

one is located on site. 

4.1.2 Opportunity

Reduction Target: 68 Bcf/year and a portion 

of 237 Bcf/year 

The 2011 Greenhouse Gas Inventory estimates that 

well completions, workovers, and well cleanups emit 

approximately 305 Bcf of methane annually, 43 percent 

of total natural gas systems methane emissions.39 Of this 

amount, well completions and workovers contributed about 

68 Bcf/year, and well cleanups contributed about 237 Bcf/

year, as shown in Table 2. Green completions may be used 

to control a significant fraction of emissions from well 

completions and workovers. Green completions can also be 

used to control a portion of the emissions from well cleanups, 

also known as liquids unloading. 

There remains considerable uncertainty in wellhead 

emissions. In the decade prior to the 2011 Greenhouse 

Gas Inventory, the EPA revised its well emission estimates 

upward several times, and it reports continued uncertainty 

in the 2011 inventory estimates. It is likely that well methane 

emissions are still underestimated. 

Green completions alone could enable 

the United States to achieve more than 

30 percent of its O&G industry methane 

reduction opportunity

In 2005, the EPA estimated that an average of 7,000 Mcf of 

natural gas can be recovered during each green completion.40

In 2011, the EPA increased its reduction estimate to 8,200 

Mcf per green completion.41 As part of its analyses relating 

to Subpart W of the Greenhouse Gas Reporting Rule, the EPA 

calculated the average emissions reduction to be 9,175 Mcf 

per green completion.42 In a 2011 Lessons Learned report, the 

EPA estimated that an average of 10,800 Mcf could be saved 

per green completion.43

The EPA has found that green completions can be a major 

contributor to methane reductions on a national scale. 

In 2008, the EPA’s Natural Gas STAR Program attributed 

50 percent of the program’s total reductions for the O&G 

production sector to green completions.44 Considering 

the promising technical and economic feasibility of green 

completions, a very large fraction of the emissions from 

Colorado Oil & Gas Conservation Commission, “Proposed Rules for Green Completions” presentation June 27, 2008

Figure 12: Green Completion Equipment
PAGE 21 | Leaking Profits

well completions and workovers, and a portion of the 

emissions from well cleanups, could be captured using green 

completions. 

The commercial viability of green completion equipment 

has been so well demonstrated that it is now required in 

several states: 

n	 Colorado requires green completions on all oil and 

gas wells unless it is not technically and economically 

feasible.45

n	 Fort Worth, Texas requires green completions for all 

wells that have a sales line nearby, and for wells that are 

shut-in while gas is conserved, unless the operator can 

show that this requirement would endanger the safety of 

personnel or the public.46

n	 Montana requires VOC vapors (including methane) 

greater than 500 British Thermal Units (BTUs) per cubic 

foot from wellhead equipment with the potential to 

emit 15 tons per year or greater, to be routed to a control 

device (such as a flare), or to a pipeline for sale.47

n	 Wyoming has required green completions in the JonahPinedale Anticline Development Area (JPAD) since 2007. 

More recently, Wyoming has expanded this requirement 

to all Concentrated Development Areas of oil and gas in 

the state.48

Such rules mandating green completions are an excellent 

method to help reduce emissions of greenhouse gases and 

toxic air pollutants, and exceptions written into these rules 

allowing operators not to use green completion technology 

should be very narrow, limited to only when it is proven to be 

unsafe or technically infeasible.

 The API reports that there are only 300 green completion 

units in operation in the United States with the ability to 

complete 4,000 wells per year.49 This corroborates the upper 

end of the EPA’s estimate that the U.S. O&G industry has a 

capacity to implement approximately 3,000 to 4,000 green 

completions per year.50

 While some operators report use of green completions at 

a portion of their operations in the United States, it is clear 

that opportunities abound for much wider deployment of 

green completions to reduce methane emissions. The API 

estimates that only 20 percent of U.S. gas well emissions are 

currently being captured by green completions and that an 

additional 16,000 wells per year could be processed if there 

were sufficient green completion equipment capacity.

4.1.3 Proposed EPA Regulations 

The EPA is proposing to require green completions to 

control emissions from all production wells that undergo a 

hydraulic fracture treatment. The EPA proposes to exempt 

exploration wells and all other gas wells that are not 

hydraulically fractured.

Therefore, the EPA expects that more than 95 percent of 

emissions from well completions and workovers would be 

controlled using green completions. NRDC applauds the 

EPA’s proposed regulations for targeting significant emissions 

reductions during well completions and recompletions. Still, 

green completions should be required for all wells where 

technically feasible, including well cleanups and wells that 

are not hydraulically fractured. Such a requirement can be 

expected to lead to the rapid increase in availability of green 

completion equipment. 

4.1.4 Profit 

Green completions provide an immediate revenue stream 

by routing to a gas sales line gas (methane and condensates) 

which would otherwise be vented into the atmosphere 

or flared. Alternatively, captured gas can be used for fuel, 

offsetting operating costs or be re-injected to improve 

well performance. Industry has demonstrated that green 

completions are both an environmental best practice and 

profitable. 

For each unconventional gas well green completion, there 

is an opportunity to generate about $28,000 to $90,000 in 

profit, based on capture rates of 7,000 to 23,000 Mcf per well, 

as shown in additional detail in Appendix A, Table A1. The 

EPA currently estimates the cost of implementing a green 

completion as high as $33,000 (for rented equipment).51,52 

Based on these and other estimates, green completions 

using rented equipment will typically pay out immediately 

while those with purchased equipment will pay out within 

a year.53 NRDC recognizes wells currently chosen for green 

completions are likely to be more productive and therefore 

profitable than average wells going forward. 

 Operators with a sufficient number of wells to amortize the 

cost of the equipment are finding it economically attractive 

to invest in their own green completion technology rather 

than to rent equipment. Most companies that have gone 

this route report a one- to- two year payout for investment 

in purchasing green completion equipment, and substantial 

profitability thereafter.54

Smaller operators can rent green completion equipment 

from a contractor. Renting equipment will result in a lower 

profit margin because there is usually a slightly higher 

operating cost attributed to equipment rental versus 

equipment ownership. Still, the payout for this investment 

would occur quickly if a contractor was hired and the 

operator paid only a per well green completion equipment 

rental charge. As long as the gas captured and sold exceeded 

the equipment rental charge, payout would be immediate. 

In a 2009 study conducted for New York State, ICF 

Incorporated found that equipment payouts may be as short 

as three months. ICF also found that companies electing to 

conduct green completions in 2005 made more than $65 

million in profits.55 
PAGE 22 | Leaking Profits

Examples listed below demonstrate how profitable green 

completions can be. The data is provided in the form 

reported by each company. However, these examples show 

that green completions are profitable, and generally pay out 

in less than two years: 

n	 In 2004, Devon Energy reported an average incremental 

cost to perform a green completion of $8,700 per well at 

its Texas Fort Worth Basin operations. Devon estimated 

that it made a profit of $50,000 per well by selling the 

captured gas to market and achieved a total emission 

reduction of 6.16 Bcf at its operations in year 2005. 78 

percent of the methane captured (4.8 Bcf) was attributed 

to green completion methods.56,57

n	 BP reported an initial investment cost of $1.4 million 

to purchase a portable three-phase separator, sand 

trap, and tanks to conduct green completions. By 2005, 

BP completed 106 wells using this equipment and 

reported an average gas recovery of 0.35 Bcf per year, 

and condensate recovery of 6,700 barrels per year. The 

company’s investment paid out in less than two years. 

Thereafter, the equipment brought in a profit of at least 

$840,000 per year.58 In 2007, BP reported that green 

completions had netted a profit of $3.4 million on an 

investment of $1.2 million, with a payout of 0.7 years, and 

a capture of 130 Mt of methane per well.59

n	 Williams reported $159 million in revenue from green 

completions in its Colorado Piceance Basin Operations

from 2002 to 2006, on an investment of $17 million, for a 

net profit of $142 million.60 Williams’ data was based on 

1,177 wells and an average gas recovery of approximately 

91 percent. 

n	 EnCana Corporation, the largest natural gas producer 

in North America, which produces 1.5 percent of United 

States daily gas needs,reported that green completion 

methods were extremely profitable in the Jonah Field in 

Wyoming, yielding a net present value (NPV) of more 

than $190 million.61 EnCana’s initial investment in the 

portable green completion equipment for the Jonah Field 

paid out in the first year.

n	 Anadarko reported an increased operating profit of $10.3 

million per year for the period 2006 to 2008 due to green 

completions on an average of 613 wells per year.62

4.1.5 Additional Benefits

Green completions provide a number of additional benefits, 

aside from profitability and methane emission reductions. 

Green completions: 

n	 Collect potentially explosive gas vapors, rather than 

venting them into the atmosphere (improves well site 

safety, reduces worker exposure to harmful vapors, and 

limits overall corporate liability)

n	 Reduce or eliminate the need for flaring

n	 Reduce emissions, noises, odors, and citizen complaints 

associated with venting or flaring

n	 Reduce VOCs and HAPs contained in natural gas along 

with methane. If flared and not captured, VOCs and 

HAPs generate nitrogen oxides (NOX) and particulate 

matter (PM), contributors to ground-level ozone and 

regional haze

n	 Improve well cleanup and enhance well productivity, as 

wells flow back to portable separation units for longer 

periods than would be allowed with direct venting into 

the atmosphere or flaring

n	 Reduce the need to drill new wells as more methane is 

kept in the system and brought to market

4.1.6 Limitations and Evaluation

Green completions are most successful and profitable on 

higher pressure wells that have sufficient gas reservoir 

pressure to both flow into a pressurized gas sales pipeline and 

adequately clean up the wellbore.63 

For lower pressure wells, artificial lift may be required, 

using portable compressors to withdraw gas from a 

pressurized sales gas line. The pressurized gas is then injected 

into the well to unload wellbore liquids and solids (artificial 

lift), and initiate flow. Compressors may also be needed to 

boost the lower pressure gas back into the sales line until 

normal reservoir flow and pressure is established.64 Adding 

compression to the equipment package required for a green 

completion will increase cost. 

Recognizing the existence of technical limits, Colorado sets 

boundaries on when green completions should be required: 

“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. Green 

completion practices are not required for exploratory 

wells, where the wells are not sufficiently proximate 

to sales lines, or where green completion practices are 

otherwise not technically and economically feasible.

An operator may request a variance from the Director 

if it believes that employing green completion practices 

is not feasible because of well or field conditions or that 

following them in a specific instance would endanger the 

safety of well site personnel or the public.”65

In the event that Colorado issues a variance from using green 

completion techniques due to technical or safety constraints, 

it still requires the use of Best Management Practices to 

minimize the amount of methane emitted: 

“In instances where green completion practices are 

not technically feasible or are not required, operators 

shall employ Best Management Practices to reduce 

emissions. Such BMPs may include measures or 

actions, considering safety, to minimize the time 

period during which gases are emitted directly to the 

atmosphere, or monitoring and recording the volume 

and time period of such emissions.”
PAGE 23 | Leaking Profits

Because pipelines are typically not installed at a natural 

gas production site until it is confirmed that an economical 

gas supply is found, gas from the first well is often flared or 

vented during drilling and completion activities. However, 

once a pipeline is installed, subsequent wells drilled 

on that same pad would be in a position to implement 

green completion techniques. Operators often point to 

the lack of pipeline infrastructure as a primary reason a 

green completion may not be possible, in particular at oil 

production facilities that do not have a nearby gas sales 

line. However, there are also alternatives to piping methane, 

such as using it on-site to generate power, re-injecting it to 

improve well performance, or providing it to local residents 

as an affordable power supply. 

Figure 13 provides a simplified flowchart showing the 

basic steps for evaluating whether a green completion is 

technically feasible and profitable.

4.2 Plunger Lift Systems 

Older gas wells stop flowing when liquids (water and 

condensate) accumulate inside the wellbore. As liquid 

builds up in the wellbore it creates backpressure on the 

hydrocarbon formation, further reducing the gas flow rate.

Methane gas is emitted when companies open wells to vent 

gas to the atmosphere to unload wellbore liquids (water and 

condensate that accumulate in the bottom of the well) in 

order to resume gas flow. The industry typically refers to this 

process as “blowing down the well,” a “well blowdown,” or a 

“well deliquification.”

Eventually, even a well’s own gas pressure becomes 

insufficient to flow accumulated liquids to the surface and 

the well is either shut-in as uneconomic, or some form of 

artificial lift is installed to transport the liquids to the surface. 

Plunger lift systems are one method of lifting accumulated 

liquids in the wellbore to the surface. In this method, 

methane gas can be captured and sold, rather than vented to 

atmosphere as waste.

4.2.1 Technology Description

Installation of plunger lift systems provides an immediate 

revenue stream by routing methane gas to a gas sales line that 

would otherwise be vented. Industry has demonstrated that 

plunger lift systems are both an environmental best practice 

and profitable when addressing mature gas wells with back 

pressure from liquids.

Accumulation of liquid hydrocarbons and liquids in 

the well tubing of mature gas wells can halt or impede gas 

production. Historically, well operators would vent these 

mature gas wells to atmosphere to aid in expelling the liquids 

from the well tubing. Alternatively, plunger lift systems can be 

installed in a well to lift the liquids out of the well (Figure 14).

There are a number of deliquification methods that can be 

used on a mature gas well singly or in combination, such as 

sucker rod pumps, electric submersible pumps, progressing 

cavity pumps, compression, swabbing, gas lift, and smaller 

diameter tubing (velocity strings), but most of these methods 

require the addition of energy.66 The plunger lift system is a 

low-cost system that uses the well’s own natural energy to 

complete the deliquification process. This technology is 

particularly useful at well sites that do not have power. 

Plunger lift systems work by using the natural gas pressure 

that builds up in the casing tubing annulus to push a metal 

plunger up the well tubing, forcing a column of fluid to 

the surface. Gas and liquids are both collected. Liquids are 

separated from the gas, which is then routed to the pipeline 

for sale.

 Figure 13: Green Completion Evaluation Flowchart

Is gas sales pipeline infrastructure in place? 

on Page 26, accessible to section 4.1.5

Can methane be collected 

for local fuel use? 

Is well pressure sufficient to flow to a pipeline? 

Yes 

No 

Evaluate overall economics. 

Is a green completion profitable? 

Document economic infeasibility. 

No 

Implement Green Completion 

Yes 

Yes No 

Yes No No 

Is additional 

compression 

economic? 
PAGE 24 | Leaking Profits © Lure Creations, adapted from Parveen Industries.

Automated plunger lift systems have the added benefit of 

reducing the number of personnel that would be required to 

manually vent the well and extending the production life of 

the well.67

One vendor reports that plunger lift systems increase 

overall gas productivity and sales from each well by 10 to 

20 percent.68 

4.2.2 Opportunity

Reduction Target: 237 Bcf/year Less Green 

Completions Reduction

Natural gas production is now predominantly occurring in 

unconventional formations: low permeability sands, shale, 

and coal bed methane reservoirs.69 In its comments on the 

EPA’s proposed NSPS regulations for plunger lift systems, the 

American Petroleum Institute said: “According to the Energy 

Information Administration...some 338,056 (73 percent) wells 

out of a total gas well inventory of 461,388 produce 90 Mcf 

of gas (15 BOE or less) or less per day...These low rate wells 

are either impaired by liquids accumulation or are using a 

deliquification method to produce.”70

Maximizing production from each well drilled can 

minimize the need to drill new wells and therefore reduce 

overall environmental impacts from natural gas production. 

However, low gas rate wells eventually cease production due 

to liquid accumulation in the wellbore and are often shut-in, 

unless a deliquification technique is employed on the well. 

The EPA estimates that 4,700 to 18,250 Mcf/year of 

methane gas can be recovered per well with plunger lift 

systems.70,71 In 2011, the EPA estimated that 237 Bcf of 

methane was emitted from well cleanups annually. A large 

fraction of these emissions could be controlled using plunger 

lift systems. 

Plunger lift systems are low cost and use a 

well’s own natural energy

4.2.3 Proposed EPA Regulations 

The EPA’s proposed NSPS regulations would not require the 

use of plunger lift systems to address well cleanups. Even if 

plunger lifts are more widely used than previously assumed, 

we strongly recommend that the EPA revise its proposal to 

require plunger lift systems to ensure that such systems are in 

use at all feasible sites. 

NRDC acknowledges that there are many options for well 

deliquification. In any case, there is a methane control target 

(237 Bcf) that should be addressed by plunger lifts or other 

well deliquification methods that capture methane with 

similar efficiency and effectiveness. NRDC recommends that, 

while operators should have flexibility in selecting among 

the options, the basis for selection should be minimizing 

methane emissions.

4.2.4 Profit

Installing a plunger lift system in a gas well involves a small 

initial investment, estimated by the EPA to be between $2,600 

and $10,400 per well.72 Plunger lift system maintenance 

may cost about $1,300 per year, but yields other operational 

savings such as avoided chemical treatment of about $13,200 

per year, resulting in a net savings. 

Each plunger lift installed in an older gas well could 

result in 600 to 18,250 Mcf per year of recovered gas, valued 

at $2,000 to $103,000, when operations and maintenance 

savings are included. The value of methane gas recovered and 

sold rapidly covers that initial investment cost, as shown in 

greater detail in Appendix A, Table A2.

Most companies report a less than one-year payout and 

substantial profit thereafter, depending on the gas recovery 

rate. Future profits will be offset eventually by declines in 

gas recovery rates, and by minimal additional operating and 

maintenance costs, but since most plunger lift systems pay 

back in less than a year, plunger lift installations typically 

start profitable and remain profitable for many years after the 

initial investment. 

The examples below, reported by industry, illustrate the 

profitability of plunger lift systems: 

n	 Between 1995 and 1997, Mobil Oil installed plunger lifts 

in 19 wells at its Big Piney Field in Wyoming, reducing its 

emissions by 12,166 Mcf per year.73

Gas Lifted to Surface 

Plunger Lift System

Installed in Well 

Gas Production Zone

Figure 14: Plunger Lift System Schematic
PAGE 25 | Leaking Profits

n	 In 2000, BP installed plunger lift systems with automated 

controls on approximately 2,200 wells in the United 

States, and reported a 50 percent reduction in gas well 

blowdowns for liquid unloading by year 2004.74 By 2006, 

BP reported the installation of “smarter” plunger lift 

automation systems, achieving a $15.5 million per year 

profit on an average annual recovery of 1,424 Mcf of 

methane gas per well.75

n	 In 2000, Conoco reported that installation of plunger lift 

systems in its low-pressure gas wells in Lea County, New 

Mexico reduced operating costs by more than 70 percent.76

n	 In 2006, Amoco reported that it installed plunger lifts 

at a cost of $13,000 per well at its Midland Texas field, 

resulting in electricity, well workover, and chemical 

treatment savings of $24,000 per year per well. In addition 

there was a small increase in gas production, which added 

about an additional $79,000 in profit to each well per year, 

for a total benefit of more than $100,000 per well.77

n	 In 2007, Devon Energy reported a 1.2 Bcf reduction of 

vented methane gas in its operations due to installation 

of plunger lift systems.78

n	 In 2010, the New Mexico Oil and Gas Association 

submitted testimony to the New Mexico Environmental 

Improvement Board confirming that plunger lift systems 

have been technically viable and economically attractive 

in the San Juan Basin.79

4.2.5 Additional Benefits

Automated plunger lift systems continuously optimize gas 

production. Regular fluid removal limits the periods of time 

that liquid loading “kills” the well and halts gas production. 

The mechanical action of the plunger traveling up and 

down the tubing also prevents buildup of scale and paraffin 

in the tubing. Preventing excess scale and paraffin buildup 

reduces the cost of the chemical or mechanical swabbing 

treatments required to remove this buildup, and, in more 

serious cases, the cost of well workovers. The EPA reports 

additional savings associated with plunger lift systems 

ranging from $6,600 to $14,500 per well for reduced chemical 

treatment and workover costs.80 

Gas venting near well operations creates potentially 

explosive vapor levels that can pose a human health hazard. 

Collection of potentially explosive gas vapors, rather than 

venting the gas to atmosphere, improves well site safety, 

reduces worker exposure to harmful vapors, and limits overall 

corporate liability. 

Additionally, gas capture and sale reduces emissions, 

noises, odors, and citizen complaints associated with venting.

Unprocessed natural gas contains VOCs and HAPs, along 

with methane. Therefore, capture of this gas also reduces 

VOCs and HAPs pollution. 

4.2.6 Limitations and Evaluation

Plunger lift systems are useful in gas wells that tend to fill 

with liquid, and have sufficient gas volume and pressure to 

power the plunger lift system. Such factors should be taken 

into account in determining applicability. In some cases, 

wells installed with plunger lifts may need to be vented for 

a short period of time to generate the differential pressure 

needed to resume well liquid removal. Even in this case, total 

methane emissions are substantially reduced. Also, a plunger 

cannot be run in a well bore with changing tube sizes, or wells 

with highly deviated directional or horizontal well bores.

Figure 15 provides a simplified evaluation flowchart 

showing the basic steps for evaluating whether a plunger lift 

system will be technically feasible and profitable.

 Figure 15: Plunger Lift System Evaluation Flowchart

Does liquid loading in the gas well impede the gas flow rate? 

Is well pressure and gas flow rate sufficient to power the plunger lift system? 

Evaluate overall economics. 

Is a plunger lift system profitable? 

Document economic infeasibility

No 

Install Plunger Lift System 

Yes 

Yes 

Yes 

No 

Plunger lift system is not necessary

Document technical infeasibility

No 
PAGE 26 | Leaking Profits

4.3 Tri-Ethylene Glycol Dehydrator

Emission Controls

Glycol dehydrators are used to remove moisture from natural 

gas to improve gas quality, minimize corrosion in the gas 

sales line, and mitigate gas hydrate formation. A number of 

different glycols can be used in dehydration systems (e.g. 

triethylene glycol (TEG), diethylene glycol (DEG), ethylene 

glycol (MEG), and tetraethylene glycol (TREG)). TEG is the 

most commonly used glycol in industry.81 TEG dehydrators 

vent methane gas to the atmosphere, but in many cases 

methane gas can be captured instead. 

4.3.1 Technology Description

In some cases, if the design criteria can be met, a TEG 

dehydrator can be replaced with a desiccant dehydrator 

(see Section 4.4). However, desiccant dehydrators are 

limited to low gas flow rates—less than 5 MMcfd—and have 

temperature and pressure limitations. Therefore, for higher 

gas flow rates, the best solution is often to retrofit existing 

TEG dehydrators with emission controls. 

A typical glycol dehydration system includes a glycol 

contactor, a glycol exchange pump, a driver to run the 

pump, and a glycol regenerator and reboiler. In some cases, 

a condenser is also installed downstream of the glycol 

regenerator. Figure 16 provides a schematic for a typical 

glycol dehydration unit. As shown in the diagram, natural 

gas with moisture content exceeding pipeline specifications 

(“wet gas”) enters the glycol dehydration system and 

moisture is removed to achieve pipeline specifications (“dry 

sales gas”). 

A typical glycol dehydration system includes the following 

components: 

n	 Glycol contactor: Wet gas enters the glycol contactor. 

Glycol removes moisture from the gas by the process 

of physical absorption. Along with removing moisture, 

the glycol also absorbs methane, VOCs, and HAPs. Dry 

gas exits the glycol contactor absorption column and 

is either routed to a pipeline or a gas plant. The glycol 

contactor unit plays the primary role in dehydrating the 

gas to pipeline specifications, but the rest of the glycol 

dehydration system is required to convert the now 

moisture rich glycol back into a lean product that can 

be reused to dehydrate more incoming gas. Therefore, 

the next step in the process is to route the moisture rich 

glycol to regenerator and reboiler units to remove that 

moisture. 

n	 Glycol regenerator & reboiler: Glycol loaded with 

moisture, methane, VOCs, and HAPs (“rich glycol”) exits 

the bottom of the glycol contactor unit and is routed to 

the glycol regenerator and reboiler units to remove the 

absorbed components and return “lean” glycol back 

to the glycol contactor. If emission controls are not 

installed, methane, VOCs, HAPs, and water are boiled 

off and vented to atmosphere from the regenerator and 

reboiler units. One way to limit the amount of methane, 

VOCs, and HAPs emitted to the atmosphere from the 

regenerator and reboiler units is to install a flash tank 

separator.

Water Vapor, Methane, VOCs, 

HAPs Vented to Atmosphere

Add Flash Tank 

 Separator 

Flash Gas Used for Fuel 

Replace with 

Electric Driver 

Note: not all units 

have a condenser 

Route Skimmer 

Gas to be Used

as Fuel 

 

Optimize Glycol

Circulation Rate

former 15

 Figure 16: Glycol Dehydration Unit Schematic

Source: Wikimedia Commons, Wikipedia: Glycol Dehydration
PAGE 27 | Leaking Profits

n	 Flash tank separator: Installation of a flash tank 

separator between the glycol contactor and the glycol 

regenerator/reboiler units creates a pressure drop in the 

system, allowing methane, and some VOCs and HAPs, 

to flash out of, or separate from, the glycol. The amount 

of pressure drop that can be created is a function of the 

fuel gas system pressure or compressor suction pressure 

because the methane gas flashed-off at the flash tank 

separator is then sent to be used as fuel in the TEG 

reboiler or compressor engine. Simply put, the pressure 

can only be dropped to a pressure that still exceeds the 

fuel gas pressure, allowing the collected methane gas to 

flow into the fuel system. Flash tank separators typically 

recover 90 percent of the methane and approximately 10 

to 40 percent of the total VOCs that would otherwise be 

vented to atmosphere. Methane emissions can also be 

controlled by taking the simple step of adjusting the rate 

at which glycol circulates in the system. 

n	 Glycol recirculation pump: Methane emissions are 

directly proportional to the glycol circulation rate. 

Circulating glycol at a rate that exceeds the operational 

need for removing water content from gas unnecessarily 

increases methane emissions. Glycol circulation rates 

are typically set at the maximum to account for peak 

throughput. Gas pressure and flow rate decline over time, 

requiring the glycol circulation rate to be adjusted to 

meet operational need. Optimizing the glycol circulation 

merely requires an engineering assessment and a 

field operating adjustment. If the glycol dehydration 

unit includes a condenser, methane emissions can be 

collected and used for fuel or destroyed rather than being 

vented to atmosphere. 

n	 Condensers: Some glycol reboilers have still condensers 

to recover natural gas liquids and reduce VOCs and HAPs 

emissions. However, condensers do not capture methane 

(because it is a non-condensable gas); therefore, the 

addition of a condenser does not reduce methane 

emissions. In these cases, methane gas is typically vented 

to atmosphere. Alternatively, this methane gas (called 

“skimmer gas”) can be routed to the reboiler firebox or 

other low-pressure fuel gas systems.82

n	 Electric pumps or energy-exchange pumps:

Historically, gas-assisted glycol pumps have been used. 

Where there is an electric supply, the gas-assisted glycol 

pumps can be replaced with an electric pump. Gasassisted pumps are driven by expansion of the highpressure gas entrained in the rich glycol that leaves the 

contactor, supplemented by the addition of untreated 

high-pressure wet (methane rich) natural gas. The 

high-pressure gas drives pneumatic pumps. Much like 

pneumatically operated valves, pneumatically operated 

pumps vent methane. Electric pumps would reduce 

emissions, since they do not vent methane.

Regarding electric pumps or energy-exchange pumps, the 

EPA reports: 

 “The mechanical design of these pumps places wet, 

high-pressure TEG opposed to dry, low pressure TEG, 

separated only by rubber seals. Worn seals result in 

contamination of the lean (dry) TEG making it less 

efficient in dehydrating the gas, requiring higher 

glycol circulation rates. Replacing gas-assisted pumps 

with electric pumps increases system efficiency and 

significantly reduces methane emissions.”83

By comparison, electric pumps have lower emissions and no 

pathway for contamination of lean TEG by the rich TEG. 

In summary, there are four straightforward solutions 

readily available to control methane emissions from TEG 

dehydrator units:

n	 Installing a flash tank separator

n	 Optimizing the glycol circulation rate

n	 Rerouting the skimmer gas

n	 Installing an electric pump to replace the natural gas 

driven energy exchange pump

4.3.2 Opportunity

Reduction Target 8 Bcf/year

The 2011 Greenhouse Gas Inventory estimates that gas 

dehydration systems emit approximately 8 Bcf of methane 

annually.84

In 2009, the EPA estimated that there were approximately 

36,000 glycol dehydrators in operation in the U.S. natural 

gas sector.85

While a number of large glycol dehydrators are currently 

required by the EPA to install emission controls under the 

federal Maximum Achievable Control Technology standards 

(MACT standards at 40 CFR Part 63, Subpart HH), small 

glycol dehydrators are typically exempt from federal emission 

control requirements. Many small glycol dehydrator units do 

not have flash tank separators, condensers, electric pumps, 

or vapor recovery installed on the glycol regenerator. 

Many small glycol dehydrators operating in 

the United States are exempt from 

federal emission control 

Table 5: Methane Capture Potential from TEG

Dehydrator Controls 

Technology Methane Capture Mcf/year 

Flash Tank Separator 3,650

Optimize Glycol Circulation Rate 18,250

Reroute Skimmer Gas 7,665

Install Electric Pump 5,000

Potential Methane Capture Range 3,650 to 34,565
PAGE 28 | Leaking Profits

A significant fraction of this 8 Bcf/year of emissions from this 

source can and should be captured (Table 5).

Installing Flash Tank Separator: In 2005, the EPA 

estimated that the installation of a flash tank separator, 

on average, resulted in 10 Mcf/day (3,650 Mcf/year) of 

methane gas captured for use as fuel for each TEG dehydrator 

(typically a 90 percent reduction in methane emissions).

In 2009, the EPA reported that flash tank separators 

were only installed on 15 percent of the dehydration units 

processing less than 1 MMcfd, 40 percent of units processing 

1 to 5 MMcfd, and between 65 and 70 percent of units 

processing more than 5 MMcfd.86 Chevron reported it has 

installed flash tank separators, recovering 98 percent of the 

methane from the glycol and reducing methane emissions 

from 1,450 Mcf/year to 47 Mcf/year.87

Optimizing Glycol Circulation Rate: In 2005, the EPA 

estimated that optimizing the glycol circulation rate could 

result in a wide range of methane capture from 1 to 100 Mcf/

day (18,250 Mcf/year using a median estimate of 50 Mcf/day).88

Rerouting Glycol Skimmer Gas: In 2005, the EPA estimated 

that rerouting glycol skimmer gas could result in an average 

methane capture of 21 Mcf/day (7,665 Mcf/year).89

Installing Electric Pump: In 2007, the EPA estimated that 

between 360 and 36,000 Mcf/year in methane emission 

reductions could be achieved by installing an electric pump 

to replace the natural gas-driven glycol energy exchange 

pump. The wide range in methane emission reductions is a 

function of the large variation in equipment sizes. In Table 5 

we use the number 5,000 Mcf/year per electric pump.90

In 2007, the EPA determined that the total potential 

emission reductions at any given glycol dehydration unit is 

a function of how many of these emission control solutions 

are installed, and estimated that the total reduction potential 

may range from 3,600 to 35,000 Mcf/year, or $14,600 to 

$138,000 of annual revenue. The 2011 Greenhouse Gas 

Inventory estimates the upper range of emissions at 38,000 

Mcf/year.91

4.3.3 Proposed EPA Regulations 

The EPA’s proposed air toxics standards would cover new 

and existing small dehydrators located at major sources of 

HAPs.92 The EPA classifies small dehydrators as units with 

an annual average gas flow rate less than 3 million Mcf/day 

at production sites, or 9.99 million Mcf/day at natural gas 

transmission and storage sites, or actual average benzene 

emissions less than 0.9 Mg/year. 

4.3.4 Profit

The EPA estimates that it costs on average: 

n	 $5,000 to install a flash tank separator 

n	 Less than $100 to adjust the glycol circulation rate 

n	 $1,000 per unit to reroute glycol skimmer gas, with $100 

per year of operating and maintenance costs93

n	 $1,400 to $13,000 to install an electric pump94

These technologies can be installed singly or in combination. 

Each unit, if equipped with the above technology, would 

capture approximately 3,600 to 35,000 Mcf per unit, per year. 

This translates to profits of between $14,000 and $138,000 per 

unit per year, as shown in greater detail in Appendix A Table 

A3. This technology has a payback period of less than a year, 

and can generate significant profits each year thereafter.

to the lowest level technically feasible? 

Document 

reasons emission 

controls is not 

necessary

Is a flash tank separator installed? 

Yes 

Implement Emission Control 

No Evaluate economics. 

Is a flash tank separator profitable? 

No 

Is glycol circulation rate optimized? No Optimize glycol circulation rate (no cost 

option,no economic analysis required) 

Is skimmer gas collected? No Evaluate economics. 

Is skimmer gas collection profitable? 

Is an electric pump installed? No Evaluate economics 

Is an electric pump profitable? 

Yes 

Yes 

No 

No 

Yes 

Yes 

former 5.3.2

 Figure 17: TEG Dehydrator Emission Control Evaluation Flowchart

No 

Are emission controls already installed on the TEG dehydrator to reduce emissions 

1 

2 

3 

4 
PAGE 29 | Leaking Profits

4.3.5 Additional Benefits

One of the most important benefits of TEG dehydrator 

emission controls is the opportunity to reduce the amount 

of HAPs emitted to the atmosphere, especially benzene, a 

known human carcinogen. Along with methane gas, TEG 

dehydrators vent VOCs and HAPs to the atmosphere. In 

some cases, glycol dehydrators have still condensers and 

condensate separators to recover natural gas liquids and 

reduce VOCs and HAPs. But, if these units are not installed, 

VOC and HAP components (including benzene) are vented 

into the atmosphere.95 

The installation of a flash tank separator reduces VOC 

and HAP emissions, improving air quality. The installation 

of a flash tank separator also improves the efficiency of 

downstream components (e.g. condensers) and reduces 

fuel costs by providing a fuel source to the TEG reboiler or 

compressor engine.96

4.3.6 Limitations and Evaluation

The option to reroute the skimmer gas can be employed 

only on dehydrators where a still condenser is installed. The 

following factors should be evaluated in assessing feasibility 

of installing an electric pump to replace the natural gas 

driven glycol energy exchange pump, as electricity may not 

be available at a remote well site: (1) the local electric grid’s 

potential to make electric power available to a well site, (2) 

the potential to self-generate electricity on site using waste gas 

that might otherwise be vented or flared, or (3) availability of 

solar power. 

Figure 17 provides a simplified evaluation flowchart 

showing the basic steps for evaluating whether TEG 

dehydrator emission controls are appropriate.

4.4 Desiccant Dehydrators

Desiccant dehydrators can be used as alternatives to glycol 

dehydrators to remove moisture from natural gas to improve 

gas quality, minimize corrosion in the gas sales line, and 

mitigate gas hydrate formation. Desiccant dehydrators 

do not emit significant quantities of methane gas into the 

atmosphere, and reduce emissions by up to 99 percent. 

4.4.1 Technology Description

Desiccant dehydrators dry gas by passing the gas through a 

bed of sacrificial hygroscopic salt (the desiccant).97 The salt 

type—typically calcium chloride (CaCl2

) or lithium chloride 

(LiCl)—is selected based on gas temperature and pressure, 

and to match the gas operating conditions, as shown in 

Figure 18. Unlike a traditional glycol dehydrator, there are 

no pumps, contactors, regenerators, or reboilers, and only a 

small amount of methane is released intermittently when the 

unit is opened to replace the salt. 

The amount of moisture that can be removed from a gas 

Figure 18: Desiccant Dehydrator Schematic

 

Maximum

Desiccant Level

Minimum

Desiccant Level

Inlet Wet Gas

Dry Sales Gas

Filler Hatch

Support Grid

Desiccant 

Tablets

Drain Valve

Brine

DRYING BED

stream is a function of the gas pressure and temperature. 

At high gas temperatures, desiccant dehydrators can form 

gas hydrates, which can plug the unit. Therefore, desiccant 

dehydrators are best suited for 5 MMcfd gas flow rates or less, 

with a low wellhead gas temperature (less than 70 degrees 

Fahrenheit). Glycol dehydrators are needed for gas flow 

rates exceeding 5 MMcfd, for higher gas pressures, or when 

operation is required over a wide range of pressures.98

4.4.2 Opportunity

Reduction Target: 8 Bcf/year 

The 2011 Greenhouse Gas Inventory estimates that gas 

dehydration systems emit approximately 8 Bcf of methane 

annually.99

Desiccant dehydrators can be used to replace an existing 

TEG dehydrator. When this occurs, there is an initial capital 

investment required. For example, a 1 MMcfd unit costs 

about $12,500 to $16,000, but the operating and maintenance 

costs for a desiccant dehydrator are lower than those for 

a TEG unit (cost savings of about $1,800/year ).100,101 The 

EPA estimates that replacing a small TEG dehydrator with 

a desiccant dehydrator will capture about 1,000 Mcf/year 

of methane.102 Larger units—up to 5 MMcfd—will cost 

incrementally more, but will have corresponding lower 

operating and maintenance costs and higher methane 

emission recovery.103

Of the 8 Bcf/year reduction target for dehydrators, most 

of the emissions are from small dehydrators that are exempt 

from MACT standards. Using desiccant dehydrators to 

replace aging glycol dehydrators, or as a lower emission 

alternative for new dehydration units, will reduce methane 

emissions from small dehydrators.
PAGE 30 | Leaking Profits

4.4.3 Proposed EPA Regulations 

The EPA’s proposed new air toxics standards include new and 

existing small dehydrators. Desiccant dehydrators are not 

specifically required. 

While these proposed standards would cover both small 

and large glycol dehydrators, the EPA estimates that only 

0.024 Bcf/year of methane would be captured (about 0.3 

percent of the emissions from this source). 

The EPA’s proposed standards could be strengthened by 

requiring: 

n	 Air toxics reductions of 98 percent (up from the proposed 

95 percent)

n	 Better operational practices (e.g. optimized circulation 

rates)

n	 Portable desiccant dehydrators used during 

maintenance, and desiccant dehydrators for gas flow 

rates of 5 MMcfd or less. 

4.4.4 Profit 

If a desiccant dehydrator is technically feasible in a new 

installation, it will be more profitable than a TEG dehydrator. 

In addition to having lower capital and operating and 

maintenance costs than a TEG dehydrator, it has the added 

benefit of being able to collect methane for sale. 

The EPA estimates that profit could amount to $6,000 

per year, including operations and maintenance savings. 

The initial investment of $16,000 for replacing a glycol 

dehydrator with a desiccant dehydrator is paid out in less 

than three years, as shown in greater detail in Appendix A, 

Table A4.104

In 2007, BP reported that it eliminated 858 glycol 

dehydrators, replacing them with desiccant dehydrators, for 

a $27 million profit and “immediate-payout.” This amounts 

to a profit of $31,469 per unit total, or about $31,000 per 

year averaged over a 10-year period.105

4.4.5 Additional Benefits

Unprocessed natural gas contains VOCs and HAPs, along with 

methane. Therefore, capture of this gas also reduces VOC and 

HAP pollution. 

4.4.6 Limitations and Evaluation

Desiccant dehydrators produce a liquid brine waste 

that must be either routed to a produced water tank for 

reinjection or disposed of as waste. There are also pressure, 

temperature, and gas flow limitations. 

Figure 19 provides a simplified evaluation flowchart 

showing the basic steps for evaluating whether a desiccant 

dehydrator would be an option.

4.5 DRY SEAL SYSTEMS

Centrifugal compressors are used in the production and 

transportation of natural gas. Centrifugal compressors 

installed with wet seals have high-pressure seal oil that 

circulates between rings around the compressor shaft. This 

high-pressure oil is used as a barrier to prevent gas escape. 

The seal oil absorbs methane gas, however, and later the 

methane is vented to atmosphere, when the compressor 

seal oil gas is vented in a process called “seal oil degassing” 

(Figure 20).

Instead of using seal oil (wet seal), centrifugal compressors 

can use dry seals, in which high-pressure gas is used to seal 

the compressor. Changing out wet seals and installing dry 

seals reduces methane venting (Figure 21). 

Wet seal technology is being phased out. In fact, more 

than 90 percent of new compressors are being sold with dry 

seal technology, due to the environmental and cost savings 

benefits it offers. 

Figure 19: Desiccant Dehydrator Evaluation Flowchart

Is the gas flow rate less than 5 MMcfd and 

wellhead temperature less than 70oF? 

Evaluate TEG glycol dehydrator units and 

TEG glycol emission control technology Evaluate overall economics 

Is a desiccant dehydrator profitable? 

No 

Install Desiccant Dehydrator 

Yes

Yes

No 

former 5.4.3
PAGE 31 | Leaking Profits

4.5.1 Technology Description

Dry seals prevent methane leaks by pumping gas between 

the seal rings, creating a high-pressure leak barrier when 

the compressor shaft is rotating (Figure 21). Typically, two 

dry seals are used in tandem to prevent gas leakage. When 

the compressor shaft is not rotating, the dry seal housing is 

pressed up tight against the rotating ring using a “dry seal 

spring,” thereby preventing gas leaks.106

4.5.2 Opportunity

Reduction Target: 27 Bcf/year 

The 2011 Greenhouse Gas Inventory estimates that 

approximately 1,500 centrifugal compressors with wet seals 

were operating in the U.S. O&G industry, with rod packing 

systems emitting approximately 27 Bcf of methane annually, 

a significant fraction of which can and should be captured.107

The EPA estimates that 80 percent of natural gas 

compression station methane emissions are emitted from 

compressors.108 If wet seals are used in compressors for other 

applications in gas production, those compressors can also 

emit large amounts of methane. According to the EPA, wet 

seal oil degassing may vent between 40 and 200 standard 

cubic feet per minute (scfm), compared to about 0.5 to 3 scfm 

with a dry seal.109 Dry seal technology offers a technically and 

economically feasible alternative to reduce these methane 

emissions. 

4.5.3 Proposed EPA Regulations

The EPA’s proposed NSPS regulations would require the use 

of dry seals for each new or modified centrifugal compressor 

located in the processing, transmission, and storage sectors. 

The standards would not apply to compressors at a well site or 

in the distribution sector.

The EPA estimates that the proposed NSPS would reduce 

methane emissions from compressors with wet seals by 

about 0.25 Bcf/year, about 1 percent of the compressor 

methane emissions from this source. This low control 

percentage is primarily because the NSPS would only affect 

new or modified or replaced leakage sources, while the bulk 

of the emissions are from existing sources. 

The proposed regulations could be further enhanced 

by requiring equipment and operational requirements for 

existing compressors. New compressors represent just 2 

percent of all centrifugal compressors in the processing, 

transmission and storage sectors. Compressors are added or 

replaced in these sectors at an extremely low rate. Therefore, 

a standard applying only to such compressors would leave 

most of the emissions untouched. 

Figure 21: Centrifugal Compressor Dry Seals

4.5.4 Profit

The actual costs for a dry seal system will depend on 

compressor operating pressure, shaft size, rotation speed, 

and other site-specific factors. The EPA reports that a dry seal 

retrofit costs on average $324,000, but results in an operations 

and maintenance cost savings of more than $100,000 per 

year and can generate up to $400,000 in additional annual 

revenue from captured methane, resulting in a payout of 

approximately one year.110,111 One of the major factors in the 

profit equation is the lower O&M costs for dry seals—$8,400 

to $14,000 per year—compared to wet seal costs of $140,000 

per year per compressor or more.

The EPA’s 2011 Greenhouse Gas Inventory and other sources 

estimate the leak rate to be approximately 18,000 to 100,000 

Mcf per year. If captured and sold, this could annually yield 

up to $400,000 in additional revenue, and up to $120,000 in 

operations and maintenance savings. Additional details are 

provided in Appendix A, Table A5. 

Using the EPA’s estimate that wet seal oil degassing may 

vent between 58 and 288 Mcf/day, compared to 0.7 to 4 

Mcf/day with a dry seal, and using current gas prices, an 

Figure 20: Centrifugal 

Compressor Leaks Schematic

Adapted from EPA Lessons Learned, Replacing Wet Seals with Dry Seals in Centrifugal Compressors.
PAGE 32 | Leaking Profits

operator may save up to $400,000 per year, per compressor.122

However, the actual profits will vary based on site-specific 

circumstances. 

In 2008, Petróleos Mexicanos (PEMEX) assessed the 

benefits of converting from wet seals to dry seals on 

centrifugal compressors at a compression station in 

southern Mexico.113 PEMEX found a gas savings of 33.5 scfm 

per seal, and a gas savings of 35,000 Mcf/year (resulting in 

greenhouse gas emissions reduction of 7,310 metric tons of 

carbon dioxide equivalent per year), and a profit of $126,690 

annually.114 

Targa Resources and the Gas Processors Association report 

that replacing a wet seal with a dry seal on a 6 inch shaft 

beam compressor that operates approximately 8,000 hours 

per year, leaking at 40 to 200 scfm, will pay out in four to 15 

months, yielding more than $1 million in net present value, 

assuming a 10 percent discount rate in a span of five years, 

and more than a 170 percent rate of return.115

4.5.5 Additional Benefits

Upgrading compressor seals can reduce power requirements 

and downtime, improve compressor reliability, and lower 

operating costs by eliminating seal oil costs and associated 

maintenance.116

4.5.6 Limitations and Evaluation

A compressor-specific, site-specific evaluation is necessary 

to determine if conversion to dry seals is technically feasible. 

A conversion to dry seals may not be possible on some 

compressors because of compressor housing design or other 

operational or safety factors. 

Figure 22 provides a simplified evaluation flowchart 

showing the basic steps for evaluating a dry compressor seal 

conversion.

4.6 IMPROVED COMPRESSOR 

MAINTENANCE

Reciprocating compressors leak methane from a component 

called a rod packing case. A common practice is to route the 

rod packing emissions outside the compressor building and 

vent the methane emissions directly into the atmosphere. 

Methane emissions can be reduced by replacing worn out 

rod packing.

4.6.1 Technology Description

Rod packing systems are used to maintain a seal around the 

piston rod, preventing gas compressed to a high pressure in 

the compressor cylinder from leaking, while still allowing the 

piston rod shaft to move freely. A series of flexible rings are 

fitted around the piston rod shaft, held in position by packing 

material and springs.

Methane leaks occur between the rings and piston rod 

shaft, around the outside of the rings, and between the 

packing (Figure 23). Packing leaks can occur for a number of 

reasons, such as a worn piston rod, an incorrect amount of 

lubrication, dirt or foreign matter in the packing, or packing 

material out of tolerance.117 The amount of leakage will be a 

 Figure 22: Wet to Dry Compressor Seal Evaluation Flowchart

Inventory number of compressors with wet seals 

Document technical and/or 

economic infeasibility

Use a high-flow sampler, or equivalent system to 

estimate methane leakage to confirm methane reduction 

target opportunity 

Implement Dry Seal Conversion 

No 

Yes 

Evaluate economics. 

Is conversion to dry seals profitable? 

Determine the technical feasibility of converting to dry seals 

Is it technically feasible? 

No 

 

former 5.5.3
PAGE 33 | Leaking Profits

function of the amount of misalignment between the piston 

rod, packing materials, and rings and packing case. Also, 

misalignment of the piston rod and any imperfections on the 

piston rod surface can cause leakage.118

Rod packing case leaks are also a function of the quality of 

initial installation, packing material selection, and the way in 

which the unit was operated during the initial, or break-in, 

operating period. 

the bulk of the emissions come from existing compressors. 

It does not appear that the proposed standards would 

apply when an existing compressor is taken offline for 

maintenance.

The proposed regulations could be further strengthened 

by requiring equipment and operational requirements for 

existing compressors. New compressors represent just 3 

percent of all reciprocating compressors in the processing, 

transmission and storage sectors. Compressors are added 

or replaced in these sectors at a low rate; therefore, a 

standard applying only to new compressors will leave most 

of the emissions untouched. The EPA should also require 

emission abatement at the wellhead (production sector). 

While replacement based on hours of operation is a good 

minimum threshold, the EPA should also consider requiring 

regular leak-rate tests and early replacement if leakage is 

deemed too high.

4.6.4 Profit

Operators that carefully monitor and replace compressor 

rod packing systems on a routine basis can reduce methane 

emissions and reduce piston rod wear, both of which 

increase profit.121

The 2011 Greenhouse Gas Inventory uses a leak rate of 875 

scf/hour (21,000 scf/day), equating to approximately $100 of 

gas leaking from each compressor each day it is not repaired. 

The EPA estimates that refurbishing the rings and packing 

material may cost between $135 and $2,500, depending on 

the size of the unit. Rod replacement can range from $2,400 

to $13,500, depending on the number of rods replaced.122

The pace at which replacements are necessary is a 

function of the compressor type, use, maintenance and 

operating conditions, and is highly variable. In most cases, 

though, payout is achieved in less than a year. The EPA has 

estimated that on average, the annual investment expense 

of replacing one rod packing system is about $600, with 

an initial investment of about $1,600. The methane gas 

captured has a value of about $3,500 per year, allowing 

payout to be achieved in less than half a year.123 Another EPA 

reference reports a slightly lower initial cost for replacing rod 

packing of $1,200, but with similar natural gas savings, to 

allow for payout in less than half a year.124 Additional detail is 

shown in Appendix A, Table A6. 

4.6.5 Additional Benefits

Collection of methane and other gas vapors at O&G 

operations creates a safer working environment by reducing 

potentially combustible vapors at the work site. 

4.6.6 Limitations and Evaluation

One major consideration in deciding whether to replace 

worn rod packing is the cost and feasibility of taking the 

compressor out of service to make the repair. Larger facilities 

with spare compressor capacity will not be as significantly 

Figure 23: Reciprocating Compressor Rod Packing 

Leaks Schematic

Adapted from EPA 2009 Methane to Market Presentation. 

4.6.2 Opportunity

Reduction Target: 75 Bcf/year 

In 2006, the EPA estimated that more than 51,000 

reciprocating compressors were operating in the U.S. natural 

gas industry with, on average, four cylinders each, for a 

total of more than 200,000 piston rod packing systems in 

service.119 The 2011 Greenhouse Gas Inventory estimates that 

these systems emit 75 Bcf of methane annually, a significant 

fraction of which can and should be captured.120

As with centrifugal compressors, an impediment to rod 

packing replacement is the equipment downtime required 

to make the replacement. However, routine repair and 

maintenance is a good business practice. 

4.6.3 Proposed EPA Regulations

The EPA’s proposed NSPS regulations for reciprocating 

compressors require replacement of rod packing every 26,000 

hours of operation (approximately every three years). These 

standards would only apply to reciprocating compressors 

at processing stations, gathering and boosting stations, 

transmission stations and underground storage facilities. The 

standards would not apply to compressors at a well site or 

beyond the city gate (distribution sector).

The EPA estimates that the proposed NSPS regulations 

would reduce emissions from reciprocating compressors 

by about 0.3 Bcf/year, less than 1 percent of the methane 

emissions from these sources. This is primarily because the 

NSPS would only apply to new or replaced reciprocating 

compressors starting from the time of installation, whereas 
PAGE 34 | Leaking Profits

affected as smaller operations, where repairs may require a 

complete shutdown. Other variables affecting cost savings 

include the amount of wear already on the rings and rod shaft, 

fit and alignment of packing parts, and cylinder pressure. 

Figure 24 provides a simplified evaluation flowchart 

showing the basic steps for evaluating rod packing 

replacement.

controller is defined by the EPA Natural Gas STAR Program 

as a device that releases 6 scf/hour or more. Converting 

high-bleed controllers to low-bleed controllers, or moving 

away from gas-operated controllers altogether in favor of 

instrument air controls, reduces methane emissions. 

Colorado requires O&G operators to install low-bleed 

or no-bleed pneumatic controllers at all new facilities and 

whenever a device is repaired or replaced, if technically 

feasible.125 Wyoming’s Oil and Gas Production Facility 

Guidance includes upgrading to low-bleed or no-bleed 

pneumatic controllers, or routing methane to a collection 

system during a repair or replacement.126

4.7.1 Technology Description

Pneumatic controllers use clean, dry pressurized natural gas 

to provide a power supply to measure process conditions (e.g. 

liquid level, gas pressure, flow rate, temperature) and control 

Figure 25: Pneumatic Controller

Level Control 

Temperature Control 

Flow Control 

Pressure Control 

Shut-off Valve 

Gas 

Dehydrator To Pipeline 

WELLHEAD 

Separator Compressor 

Figure 26: Pneumatic Controller Locations in Natural Gas Production

Harvey Consulting, LLC © Adapted from EPA 2008 Methane to Market Presentation 

former 5.7.2

 

Establish rod packing leak rate for new rod packing 

Determine the leak rate threshold where it is 

profitable to replace the rod packing 

Monitor the leak rate to determine the optimal rod 

packing replacement timing 

Replace Worn Rod Packing 

Figure 24: Rod Packing Replacement 

Evaluation Flowchart

former 5.6.2

iStockphoto

4.7 LOW-BLEED OR NO-BLEED

PNEUMATIC CONTROLLERS

Pneumatic controllers are used to regulate pressure, gas flow, 

and liquid levels, and to automatically operate valves. They 

are used extensively in the O&G industry. 

Pneumatic controllers are designed to release methane 

gas to the atmosphere as part of normal operations. Some 

pneumatic controllers bleed at a low rate (low-bleed) 

and others bleed at a high rate (high-bleed). A high-bleed 
PAGE 35 | Leaking Profits

the conditions to a set point. Figure 25 shows a pneumatic 

controller. Figure 26 shows the locations in O&G operations 

where pneumatic controllers may be used.

There are three main pneumatic controller designs: 

1. Intermittent bleed controllers that release gas only when 

the valve is stroked open or closed 

2. Continuous bleed controllers that modulate flow, liquid 

levels, or pressures

3. Self-contained controllers that release gas back into 

piping and not to the atmosphere127

There are four main options for reducing methane emissions 

from pneumatic controllers: 

1. Replacing high bleed pneumatic controllers with low- or 

no-bleed controllers

2. Retrofitting pneumatic controllers with bleed 

reduction kits 

3. Converting natural gas pneumatics to instrument air

4. Performing routine maintenance to repair leaking 

gaskets, tube fittings, and seals

4.7.2 Opportunity

Reduction Target: 99 Bcf/year 

The 2011 Greenhouse Gas Inventory estimates that pneumatic 

controllers vented 99 Bcf of methane into the atmosphere.128

Emissions are primarily generated from the production, 

processing, and transmission and storage sectors. The 

EPA also estimates that84 percent of pneumatic controller 

emissions come from O&G production.129 According to the 

American Petroleum Institute, there are approximately 

1 million existing wells, and three controllers per well, 

indicating that there are a minimum of three million 

controllers in operation at well sites alone. The EPA reports 

that the typical high-bleed controller releases 140 Mcf/year 

of gas to the atmosphere.130 Fortunately, nearly 80 percent 

of all high-bleed pneumatic controller can be replaced 

with low-bleed equipment or retrofitted to reduce methane 

emissions.131 

Taking into account the EPA’s assessment that 80 percent 

of high-bleed devices can be replaced or retrofitted, we 

consider that a very large fraction of the 99 Bcf/year 

emissions can be captured. 

4.7.3 Proposed EPA Regulations 

The EPA’s proposed NSPS regulations require instrument air 

controllers that have zero methane emissions to be installed 

at processing plants. The EPA also proposes that low-bleed 

pneumatic controllers, with a limit of 6 scfh, be used in the 

production, transmission, and storage sectors. Requirements 

would apply to newly installed pneumatic controllers, 

including replacement of existing devices. The proposal 

would exclude pneumatic controllers that are located in the 

distribution segment, as well as existing controllers.

The EPA estimates that the proposed NSPS regulations 

would reduce emissions from high-bleed pneumatic 

controllers by about 4.5 Bcf/year, or about 5 percent. The 

emission reduction is small because the proposed NSPS 

would only apply to pneumatic controllers at the time of 

installation, whereas the bulk of the emissions are from the 

existing fleet of controllers. 

NRDC recommends that the EPA should require that 

existing sources be controlled to maximize methane emission 

reductions. The EPA should also consider regulating emission 

reductions from the distribution sector, and requiring nobleed controllers at locations outside the processing sector 

where feasible. 

4.7.4 Profit

In 2005, the EPA reported that the incremental cost of 

replacing high-bleed controllers with low-bleed controllers 

was approximately $350 per device, resulting in a $1,100 

annual operating and maintenance cost savings and a 

payback of less than one year for each device.132 Natural gas 

savings of $700 or more is also possible. The EPA estimates 

that retrofitting a pneumatic controller with a bleed 

reduction kit costs, on average, $500, and pays out in nine 

months.133 An EPA Lessons Learned report from 2006 also 

reports similar cost and natural gas savings, but with smaller 

operational and maintenance savings.134

While conversion from natural gas pneumatic controllers 

to instrument air is estimated to be more costly, at $10,000 

per conversion and $7,500 in annual operating and 

maintenance costs, there are substantial annual natural gas 

savings of more than $20,000 per year and payback in less 

than two years.135,136 In 2006, the EPA estimated the cost/

benefit of replacing large gas-operated controllers with 

instrument air controllers.137 The EPA estimated the cost to be 

approximately $60,000 per controller. The natural gas savings 

were commensurately larger at approximately $80,000 per 

year, rendering the investment profitable with a payback 

period of just under one year. Additional detail is shown in 

Appendix A, Table A7 and A8.

BP reported that it replaced 11,500 high-bleed pneumatic 

controllers with low- or no-bleed controllers in six states, 

during the period of 1999 to 2002, capturing 3.4 Bcf/year .138 

The program yielded a net present value of $65 million for a 

capital investment of $4 million. BP also reported that it had 

installed 411 pneumatic pump pressure regulators, reducing 

gas use by 0.4 Bcf/year, at a cost of less than $50,000, for a net 

present value of $8.4 million. 

QEP Resources Inc., Shell Upstream Americas, Ultra 

Petroleum, Devon Energy, EnCana, and other gas producers 

in Wyoming have replaced pneumatic controllers with new 

low-bleed controllers. Instead of gas venting the gas is routed 

to a pipeline for sale.139
PAGE 36 | Leaking Profits

4.7.5 Additional Benefits

Upgrading pneumatic controllers to use instrument air 

increases operational efficiency, system-wide performance, 

and reliability. It also improves monitoring of gas flow, 

pressure, and liquid levels. Excess instrument air can be used 

for other equipment (e.g. pumps and compressor starters). 

4.7.6 Limitations and Evaluation

The EPA estimates that 80 percent of all high-bleed 

controllers can be retrofitted or replaced with low-bleed 

equipment, leaving 20 percent of the controller inventory not 

feasible for this technology.140

Figure 27 provides a simplified evaluation flowchart to 

show the basic steps for evaluating replacement of a highbleed to a low or no-bleed pneumatic controller. 

4.8 Pipeline Maintenance and Repair

Methane is typically vented into the atmosphere when a gas 

pipeline is repaired or replaced, or must be cut to install a 

new connection point. Typically an operator will isolate the 

pipeline section to be worked on by shutting pipeline valves 

on either side of the repair, replacement, or connection point. 

The gas contained in the piping section is typically vented 

into the atmosphere to eliminate a potential fire or explosion 

risk while work is completed on the piping. 

Subject to a thorough safety evaluation, alternatives exist 

to mitigate methane release. These alternatives involve either 

re-routing gas to be burned as fuel or allowing work to be 

conducted on the pipeline while it is in operation. 

During pipeline repair, methane gas venting can be 

mitigated by: 

n	 Using hot tap connections

n	 Re-injecting gas into a nearby low-pressure fuel system,

n	 Using a pipeline pump-down technique to route gas 

to sales

4.8.1 Technology Description

Hot Tap: Hot tapping a pipeline allows an operator to make 

a connection to a pressurized piping system without causing 

any service interruption. Hot tapping is completed by first 

welding a branch fitting and permanent valve body onto the 

pipeline while the pipeline remains in service. Next, the hot 

tapping machine is installed on the valve body (Figure 28). 

The hot tap pipeline cutting tool is inserted through the valve 

body and used to cut into the pipeline while maintaining 

 Figure 28: Pipeline Hot Tapping Schematic

Hot Tap Machine 

Valve Body 

Pipeline 

Valve Body Welded to Pipeline (full encirclement fitting) 

Pipeline Cutting Tool 

 Figure 27: Pneumatic Controller Evaluation Flowchart

Inventory high-bleed pneumatic controllers and 

estimate methane release rate per controller 

Evaluate the technical feasibility of replacing 

the high-bleed device with a low-bleed controller

or instrument air. Is it technically and 

economically feasible? 

Replace or Retrofit Controller 

No 

Evaluate the technical feasibility of 

replacing the high-bleed controller with 

a bleed reduction kit. Is it technically 

and economically feasible? 

Yes 

Perform routine maintenance to repair 

Yes leaking gaskets, tube fittings and seals 

No 

 

former 5.7.3
PAGE 37 | Leaking Profits

a complete seal between the valve body and the hot tap 

machine. This process does not allow any methane gas to 

escape. Once the pipeline wall is cut, the piece of pipe is 

removed along with the cutting tool by pulling both back 

through the valve body. The valve is closed and the hot tap 

machine is removed. Finally the branch line is connected 

and installed without releasing any methane into the 

environment. 

 Hot tapping is not a new technology; it has been in use 

for a number of years.141 However, hot tapping techniques 

and equipment have improved in quality, availability, and 

safety. More technicians and engineers are trained on safe 

use and operation, and necessary equipment is now available 

in the sizes typically used. 

Re-injecting gas into a low pressure fuel system: In some 

cases, complete gas evacuation is required to safely repair, 

replace, or conduct maintenance on a pipeline section. 

Rather than venting methane to the atmosphere, an operator 

can de-pressure the pipeline to a nearby low pressure fuel 

system. Some pipelines are initially designed and installed 

with a bypass connection from the high pressure pipeline 

to a lower pressure fuel gas system. If a permanent bypass 

connection does not exist, a temporary bypass connection 

can be installed.

Figure 29A: Pipeline Pump-Down Technique Using In-Line Compressor Schematic

Upstream

Pipeline Section 

Close Upstream Valve 

Downstream 

Pipeline Section 

Initially Open Downstream Valve; 

Remove Gas in Segment; Close Valve. 

Remove Gas Between Valves 

Using Inline Compressor 

Gas Compressor Gas 

Figure 29B: Pipeline Pump-Down Technique Using Portable Compressor Schematic

Upstream

Pipeline Section 

Close Upstream Valve 

Downstream 

Pipeline Section 

Close Downstream Valve 

Remove Gas Between

Valves Using Portable

Compressor 

Gas Gas 

Portable 

Compressor 

Pipeline pump-down technique: Gas can be removed 

from the pipeline by using in-line compressors along, or in 

sequence with, portable compressors. As explained above, 

an operator often will isolate the pipeline section to be 

worked on by shutting in pipeline valves on either side of the 

repair, replacement, or connection point. The gas contained 

in the piping section is then vented into the atmosphere to 

eliminate a potential fire or explosion risk. Alternatively, in 

the pipeline pump-down technique, the operator only shuts 

in one valve (the upstream valve), which stops any new gas 

from entering the pipeline section to be worked on. Then 

gas is removed from the pipeline section by running an inline compressor located downstream of the repair section. 

This technique will not completely remove all the gas in 

the pipeline section, but may reduce the gas pressure or 

concentration to a level that is safe for some repairs (Figure 

29A).

 Use of a portable compressor, alone or in addition 

to an existing in-line compressor, can remove up to 90 

percent of the gas in the pipeline segment because portable 

compressors have a 5 to 1 compression ratio, compared 

to in-line compressors that are rated at 2 to 1.142 To use a 

portable compressor, there must be a valve manifold at the 

downstream pipeline location to temporarily install the 

compressor during the repair work (Figure 29B).
PAGE 38 | Leaking Profits

4.8.2 Opportunity

Reduction Target: 19 Bcf/year 

The 2011 Greenhouse Gas Inventory estimates that routine 

maintenance and pipeline upsets resulted in 19 Bcf/year of 

methane vented into the atmosphere.143

For a pipeline ranging from 4 to 18 inches in diameter and 

operating between 100 and 1,000 psig, the EPA estimates that 

up to 2,000 Mcf of methane gas is vented when a pipeline 

is blown down to make a new connection, and 6,000 Mcf is 

vented when replacing pipe.144 The amount of gas contained 

in the pipeline section will be a function of pipeline size, 

pipeline length between isolation valves, and gas pressure. 

Thus, gas venting rates and volumes will vary substantially. 

4.8.3 Proposed EPA Regulations 

The EPA’s proposed NSPS and existing air toxics standards do 

not include pipeline maintenance and repair as a means to 

control methane. NRDC recommends that the EPA require 

methane control during maintenance and repair where safe 

and feasible. 

4.8.4 Profit

Use of a hot tap tool prevents venting gas into the 

atmosphere, allowing that gas to reach market, and 

eliminates the cost of evaluating the pipeline to install the 

connection. Hot tap profitability will vary widely based on the 

pipeline size, flow rate and number of taps done in a period 

of time. However, in general the EPA reports that payback is 

short (less than one year) and the procedure is profitable.145

The EPA estimated that the capital cost of installing a 

low pressure piping bypass to re-inject gas during a pipeline 

blowdown into a low-pressure fuel system is less than $1,000.146

The pipeline pump-down technique is most profitable for 

higher pressure, higher volume pipelines with existing in-line 

compressors, or where valve manifolding exists to easily 

connect a portable compressor. 

Overall, use of in-line compressors to remove gas from a 

pipeline during a pipeline pump-down technique is very 

profitable because there is no initial investment or rental 

costs, and payback is essentially immediate. If portable 

compressors are required, economics will vary and will 

require a site-specific evaluation. Still, this procedure is 

typically profitable, with a short payout.147 Gas collected by 

the compressors can be routed to a gas sales line. 

4.8.5 Additional Benefits

Continued operation of a pipeline during repair, 

maintenance, and installation of new connections eliminates 

disruption to gas service. 

4.8.6 Limitations and Evaluation

The use of hot tap equipment and techniques requires 

a safety review and qualified personnel to safely operate 

the equipment, and there are some cases where use of hot 

tapping equipment is not safe or recommended. In these 

cases, advice can be sought from corporate health, safety, and 

environment experts to recommend alternate ways to avoid 

methane venting. Some repair, replacement, and pipeline 

connection plans require complete gas removal from the 

pipeline and a full purge to ensure the safety of personnel. 

Figure 30 shows the basic steps for evaluating options 

to mitigate methane release from a pipeline during 

maintenance and repair work. 

Figure 30: Pipeline Maintenance and Repair Evaluation Flowchart

Will pipeline maintenance and repair work require methane gas to be vented to atmosphere? 

Document technical and/or 

economic infeasibility

Perform Hot Tap Procedure 

No 

Yes 

Can the pipeline be de-pressured 

into a low pressure fuel system? 

No No 

Is a hot tap technically 

feasible, safe and profitable? 

Is a pipeline pump-down 

technique feasible, safe, 

and profitable? 

Yes 

De-pressure LP Fuel System Yes 

Use Pipeline Pump-down Method 
PAGE 39 | Leaking Profits

4.9 Vapor Recovery Units (VRUs)

Crude oil and condensate tanks that vent to atmosphere 

emit methane through three different mechanisms: flashing 

losses, working losses, and standing losses. To avoid methane 

emissions, a vapor recovery unit can be installed on the tank 

to capture methane gas for sale or to be used as fuel. 

4.9.1 Technology Description

When liquid petroleum and natural gas are produced from a 

well, they are processed through a separator to partition oil, 

gas, and water. Oil, condensate, and gas are sold to market. 

Water is either re-injected or handled as waste. 

Liquid petroleum is sometimes stored in tanks prior 

to delivery to a pipeline or other transportation method. 

Gas liquids (condensate), in some cases, are produced 

and collected in a tank. When oil leaves the last phase of 

separation, some amount of methane gas is still trapped in 

the oil; the amount of methane is dependent on the last-stage 

separator pressure. 

Since the separator pressure is higher than the pressure 

in a crude oil or condensate tank, methane gas will escape 

from the crude oil or condensate during transfer into the 

tank. Liberation of natural gas is commonly referred to as 

“flashing” of natural gas from the oil. Flashed gas, typically, 

has a high BTU value and sales value. 

Fewer flashing losses will be generated from an oil storage 

tank if a facility reduces the operating pressure of the lowpressure separator or heater equipment just upstream of 

the oil storage tank. In these cases, less gas will be routed 

to the tanks. These optimizations can be accomplished by 

adjusting operating pressures with minimal capital and 

operational costs. 

Once crude oil and condensate are in the tank, they will 

continue to release methane gas when tank contents are 

agitated (working losses), which typically occurs during filling 

and removal of oil or condensate from the tank, and through 

standing losses during seasonal and daily temperature and 

pressure changes. 

Vapor recovery units can typically capture up to 95 

percent of the methane that would ordinarily be vented to 

atmosphere. Figure 31 shows vapor recovery equipment. 

Captured methane gas can be sold or used as fuel. Figure 32 

is a schematic showing the typical equipment configuration 

needed for a vapor recovery system. 

For sites where electric power is available, the EPA 

recommends conventional rotary or screw type compressor 

vapor recovery units. For sites without electric power, an 

Figure 31: Vapor Recovery Unit

© Remediation Services International

© M.A. Goodyear, A.L. Graham et al, Vapor Recovery of Natural Gas Using Non-mechanical Technology

 Figure 32: Vapor Recovery Unit Schematic

Bypass Line 

Gas 

Sales 

Control Valve 

Liquid Transfer Pump 

Compressor 

Flow Control 

Pressure Control 

Shut-off Valve 

Vent Line

Back Pressure

Valve 

Crude Oil Tank 

Condensate Return to Tank or to Sales Line 

Suction 

Scrubber 
PAGE 40 | Leaking Profits

ejector vapor recovery unit can be used if there is a highpressure compressor with spare capacity.148

TotalFinaElf E&P USA, Inc. reports that it recovered 

$334,000 in gas per year from its El Ebanito O&G facility tanks 

in Starr County, Texas using the Venturi Jet Ejector System 

(patented by COMM Engineering).149 Patented by Hy-Bon 

Engineering, the Vapor Jet System is another option if there 

is produced water available at the site to operate the system. 

A small centrifugal pump forces water into a Venturi jet, 

creating a vacuum effect to move low-pressure gas to a gas 

sales line or fuel use intake point. 

If gas is collected in the vapor recovery units, it must be 

at sufficient pressure to enter the intended gas pipeline or 

fuel system. If this is not the case, additional compression is 

required at an additional cost.

4.9.2 Opportunity

Reduction Target: 21 Bcf/year 

The 2011 Greenhouse Gas Inventory estimates that storage 

tanks vent approximately 21 Bcf/year of methane to the 

atmosphere.150 Some crude oil tanks are required—by EPA 

and state regulation—to install vapor recovery units, however 

many smaller tanks do not have vapor recovery units installed. 

4.9.3 Proposed EPA Regulations 

The EPA’s proposed NSPS for storage vessels would require 

at least 95 percent of VOC reductions for new and modified 

storage vessels.151 These requirements would apply to vessels 

with a throughput equal to or greater than one barrel of 

condensate per day or 20 barrels of crude oil per day, which 

are equivalent to VOC emissions of about 6 tons per year.151

Controls would include either the installation of a VRU or 

the use of a combustion device. At the same time, the EPA 

is proposing revised air toxics standards for storage vessels. 

The standards would apply to new and modified sources as 

well as existing sources. The EPA is proposing a 95 percent 

HAP reduction requirement, which would also reduce VOC 

emissions at these sources by 95 percent. In order to avoid 

duplication in compliance requirements (monitoring, 

recordkeeping, and reporting), the EPA is proposing that 

sources which are subject to the NESHAPs requirements 

would not be subject to NSPS requirements.

The EPA estimates that the proposed NSPS and NESHAPs 

regulations would reduce methane emissions from storage 

tanks by about 0.52 Bcf/year, or just under 3 percent of the 

emissions from this source, because the proposed rules 

would not apply to most of the uncontrolled tanks currently 

in operation. 

NRDC recommends that the EPA’s proposed regulations 

be strengthened by reducing the threshold for emission 

control on smaller tanks (e.g., by aggregating small tanks into 

a battery of tanks and considering emissions of the entire 

battery). The EPA should also require emissions reductions 

from produced water tanks, and require 98 percent control 

efficiency for VRUs (up from 95 percent). 

4.9.4 Profit

The amount of profit from vapor recovery units will vary 

widely, based on site-specific parameters. The EPA’s Methane 

to Markets program found that tank vapor recovery projects 

can be profitable (Table 6). Depending on size of the systems, 

Table 6: Crude Oil Tank Vapor Recovery Unit (VRU) Economics

Financial Analysis for a Conventional VRU Project

Peak Capacity

(Mcf/day)

Installation & 

Capital* Costs

O&M Costs 

(year)

Value of Gas** 

(year)

Annual 

Savings

Simple Payback 

(months)

Internal Rate 

of Return %

25 $35,738 $7,367 $18,262 $10,895 39 28%

50 $46,073 $8,419 $36,524 $28,105 20 60%

100 $55,524 $10,103 $73,048 $62,945 11 113%

200 $74,425 $11,787 $146,097 $134,310 7 180%

300 $103,959 $16,839 $365,242 $348,403 4 335%

Adapted from: EPA Natural Gas STAR, Reducing Methane Emissions with Vapor Recovery on Storage Tanks, Lessons learned from the Natural Gas STAR 

Program, Newfield Exploration Company, Anadarko Petroleum Corporation, Utah Petroleum Association, Interstate O&G Compact Commission, Independent 

Petroleum Association of Mountain States, March 23, 2010. 

*Unit cost plus estimated installation of 75 percent of unit cost 

** $4.00 per Mcf x 1/2 peak capacity x 365 (original price as per report was $6.22) 
PAGE 41 | Leaking Profits

capital and installation costs range from $36,000 to $104,000, 

methane capture at between 5,000 and 91,000 Mcf/year, and 

profits are between $4,000 and $348,000. Additional detail 

is provided in Appendix A, Table A9. Payback periods range 

from a few months to about three years, depending on flow 

rate and scale of the unit.152,153

Additional examples of tank vapor recovery 

profitability include: 

n	 Anadarko reported netting $7 million to $8 million 

between 1993 and 1999 by installing more than 300 vapor 

recovery units.154

n	 ConocoPhillips installed vapor recovery on nine tank 

batteries at a total cost of $712,500. The company’s 

investment paid out within less than four months, 

earning $189,000 per month thereafter.155

n	 Chevron installed eight vapor recovery units on crude oil 

stock tanks in 1996. This investment paid out in less than 

one year.156

If vapor recovery is not economic, an operator can 

consider minimizing the operating pressure of its lowpressure separators to reduce flashing losses, or the amount 

of methane vapors that are flashed off. For example, Devon 

Energy reported a savings of $7,000 per year after optimizing 

operating pressures in its low-pressure separators, reducing 

the amount of methane vapors that are flashed off. The 

company reported that the “primary goal of the optimization 

was to increase profits for the facility by putting more gas into 

the sales pipeline and to reduce emissions of methane with 

minimal costs to the facility.”157

4.9.5 Additional Benefits

Vapor recovery units are commonly required in ozone nonattainment areas as lowest achievable emission rate (LAER), 

or in attainment areas as best available control technology 

(BACT). Therefore, VRU use to control methane will also have 

ozone mitigation benefits. Control of tank vent gases can 

also reduce emissions of HAPs, such as benzene, toluene, 

ethylbenzene, and xylenes, VOCs, and hydrogen sulfide. 

The collection of methane and other gas vapors creates 

a safer working environment by reducing potentially 

combustible vapors at the work site. 

4.9.6 Limitations and Evaluation

Care must be taken in VRU system design to avoid oxygen 

entrainment, because oxygen in the system can pose a 

corrosion and explosion hazard.158 

VRUs are appropriate for locations that have access to a gas 

pipeline or an opportunity to use the recovered methane for 

fuel gas. If this infrastructure does not exist, the technical and 

economic feasibility may be limited.

Figure 33 illustrates the basic steps for evaluating tank 

vapor recovery options.

 Figure 33: Vapor Recovery Unit Evaluation Flowchart

Identify possible vapor recovery locations 

Document technical and/or 

economic infeasibility

Quantify the vapor loss and determine the gross value of gas 

Evaluate technical options for vapor recovery, such as 

venturi jet ejectors, vapor jets, or rotary vane, screw or 

scroll type compressors 

Implement Vapor Recovery

No 

Yes No 

Evaluate economics. 

Is tank vapor recovery profitable? 

Can separator pressure be optimized 

to reduce tank vapor loss? 

Yes 
PAGE 42 | Leaking Profits

4.10 Leak Monitoring and Repair

Methane gas leaks can occur from numerous locations at oil 

and gas facilities—valves, drains, pumps, threaded and flanged 

connections, pressure relief devices, open-ended valves and 

lines, and sample points—as gas moves through equipment 

under pressure. These leaks are called fugitive emissions. 

Fugitive emissions from equipment leaks are unintentional 

losses of methane gas that may occur due to normal wear 

and tear, improper or incomplete assembly of components, 

inadequate material specifications, manufacturing defects, 

damage during installation or use, corrosion, or fouling.159

Because methane is a colorless, odorless gas, leaks often 

go unnoticed. Historically, checks were typically performed 

on equipment components when they were first installed, 

using a soap bubble test or hand held sensor, to ensure 

the installation was leak tight. After installation, leaks were 

not typically monitored or repaired unless they became a 

significant safety hazard. For example, a significant gas leak 

would be repaired if area, building, or employee monitors 

set off alarms or if olfactory, audible, or visual indicators 

observed by facility employees identified the leak. Under 

these circumstances, the leaks had usually become an 

obvious safety concern. As a result, methane leaks at outdoor 

facilities and unmanned facilities often went undetected for 

long periods of time. 

Today, an increasing number of operators are monitoring 

and repairing leaks at their facilities. Sometimes these 

programs are instituted voluntarily, other times they are 

required by the EPA, or state and local air quality control 

agencies. For instance, the EPA has leak detection and 

repair regulations for VOCs where facilities meeting certain 

specifications are required to survey for leaks and repair 

all detected leaks. A voluntary program, also undertaken 

by the EPA Natural Gas STAR program, is called Directed 

Inspection and Maintenance. In this program facilities 

identify leaks, and then prioritize and repair them based on 

cost-effectiveness. 

4.10.1 Technology Description

Fugitive emission control is a two-part process that includes 

both a monitoring program to identify leaks and a repair 

program to fix the leak. Monitoring program type and 

frequency is a function of the type of component, and how 

the component is put to use. In most cases, monitoring 

programs can be intermittently scheduled at a certain 

frequency (e.g. monthly or quarterly) to identify leaking 

equipment. However, permanent leak sensors may be 

required to detect chronic leakers.160

There are many different monitoring tools that can be 

used to identify leaks, including electronic gas detectors, 

acoustic leak detection systems, ultrasound detectors, 

flame ionization detectors, calibrated bagging, high 

volume sampler, end-of-pipe flow measurement, toxic 

vapor analyzers, and infrared optical gas detectors. A few of 

these methods are described in more detail to familiarize 

the reader with the availability of these tools and the ease 

of measurement capability. Once leaks are identified, the 

operator can evaluate what is causing the leak and develop a 

replacement or repair program to mitigate the problem. 

For example, a hand held infrared camera can be used as a 

© Mine Safety Appliances Co.

© FLIR Systems, Inc.

Figure 35: Remote Methane Leak Detector

Figure 36: Leaking Valve as 

shown by Infrared Gas Detector

© Mine Safety Appliances Co.

Figure 34: Hand Held Infrared Camera
PAGE 43 | Leaking Profits

screening tool to detect emissions that are not visible to the 

naked eye. An infrared camera produces images of gas leaks 

in real-time. It is capable of identifying methane leaks, but 

cannot quantify the amount of the leak (Figure 34). 

Remote methane leak detectors can detect methane leaks 

from as far away as 100 feet (Figure 35). 

Infrared cameras produce photos that show methane gas 

leaks, like the leaking valve shown in Figure 36. Once a leak 

is identified, a more quantitative leak flow rate is needed, 

and other measurement devices such as high-flow samplers, 

vent-bag methods, and anemometers may be used.161 Highflow samplers capture the entire leak, measuring the leak rate 

directly for leaks up to 10 cubic feet per minute, providing 

leak flow rate and concentration data. 

In 2007, TransCanada reported significant reductions 

in fugitive emissions by implementing an effective leak 

monitoring and repair program that included measurement 

of fugitive emissions using high flow samplers to identify the 

largest and most effective repairs.162

Canadian experience with control of fugitive emissions at 

oil and gas facilities shows that: 163 

n	 Most methane leaks are from components in gas service

n	 Older facilities have the highest leak rates

n	 About 75 to 85 percent of leaks are economic to repair 

n	 The top 10 leaks at a facility generally contribute more 

than 80 percent of the emissions

The EPA has found that components in sweet gas service 

tend to leak more often than those in sour gas service, and a 

high frequency of leaks occurs from components in vibration, 

cryogenic, or thermal cycling service.164

4.10.2 Opportunity

Reduction Target: 143 Bcf/year 

The 2011 Greenhouse Gas Inventory estimates that the O&G 

industry’s fugitive emissions are 143 Bcf/year.165 Elimination 

or reduction of gas leaks retains more gas in the piping 

system for sale.

Most large gas processing plants are already subject to the 

existing NSPS regulations (40 CFR Part 60, Subpart KKK) and 

required to implement an LDAR program. However, most 

of the 457,000 miles of production gathering pipelines, and 

302,000 miles of transmission pipelines in the United States 

and 384,000 meters have not been required to implement 

LDAR programs.166

The 143 Bcf/year of fugitive emissions is largely 

uncontrolled today. Fugitive emissions management is an 

ongoing commitment, not a one-time initiative. The potential 

for fugitive equipment leaks will increase as facilities age. 

Successful fugitive emission control plans require trained 

personnel, emissions testing equipment, performance 

tracking systems, and corporate commitment. 

4.10.3 Proposed EPA Regulations 

The EPA’s proposed NSPS regulations would lower leak 

detection thresholds at gas processing plants.167 The EPA’s 

proposed NSPS regulations would reduce methane emissions 

through leak detection and repair by about 0.1 Bcf/year, less 

than 0.1 percent of the methane emissions from equipment 

leaks. 

Based on the EPA’s reported leak monitoring and 

repair profitability, NRDC recommends that more LDAR 

programs can and should be required by the EPA. Facilities 

in all sectors, including the production, transmission and 

distribution sectors should undertake LDAR programs. Best 

management practices such as optimizing processes should 

be used in tandem with LDAR programs. Not all devices 

that detect VOCs can detect methane, so facilities should 

specifically employ equipment and processes that can detect 

methane, such as infrared laser detectors. 

4.10.4 Profit

In 2009, the EPA examined the profitability of repairing 

equipment leaks at oil and gas facilities through a Directed 

Inspection & Maintenance program.168

EPA Lessons Learned documents for both gas processing 

plants and compressor stations show the average cost 

of repair was between $26,000 and $59,000 per year per 

facility.169,170 Methane captured through these programs 

averaged 30,000 and 87,000 Mcf/year. For gas processing 

plants, leak screening and monitoring cost about $32,000 

annually per plant. At both gas processing plants and 

compressor stations, the investments are profitable 

generating as much as $314,000 in profit per facility, with 

payback periods of just a few months. Additional detail is 

shown in Appendix A, Table A10.

4.10.5 Additional Benefits

The EPA has found that fugitive emission control provides 

numerous benefits including: reduced maintenance 

costs and downtime, improved process efficiency, a safer 

work environment, a cleaner environment, and resource 

conservation.171 Leaking gases may also include toxic air 

pollutants known to harm human health.

4.10.6 Limitations and Evaluation

There are no major limitations or barriers to implementation 

of a leak monitoring and repair program. 

A simplified evaluation flowchart (Figure 37) is provided to 

show the basic steps for evaluating leak monitoring and repair.
PAGE 44 | Leaking Profits

 Figure 37: Leak Monitoring and Repair Evaluation Flowchart

Complete a leak detection survey

Document technical and/or 

economic infeasibility

Identify leaking components and develop a repair 

plan. Is the repair plan profitable? 

Repair or Replace Leaking Equipment 

No 

Yes 

Do the leaks pose a safety, health, 

environmental or operating concern? 

Yes 

No 

Re-evaluate technical and economic

feasibility at next survey 
PAGE 45 | Leaking Profits

T

he technologies discussed in this report can be used to reduce significant amounts of methane 

emissions from the oil and gas production, processing, and transmission sector, while 

generating significant profits for the O&G Industry. NRDC recognizes that some companies 

have voluntarily implemented methane controls. Mandatory methane control regulations will be needed 

for companies that have not updated business-as-usual practices, embraced a culture of environmental 

responsibility, or chosen to voluntarily invest even in profitable methane control technologies. Through 

these steps methane can be kept out of the atmosphere and the health and safety of Americans can 

be improved.

NRDC supports establishing a fully effective system of 

safeguards to ensure that natural gas is produced, processed, 

stored, and distributed in a way that ensures protection of 

our water, air, land, climate, human health, and sensitive 

ecosystems (For more information on NRDC’s position on 

natural gas and fracking, go to http://www.nrdc.org/energy/

gasdrilling/). The use of natural gas in our homes, power 

plants, and industry also must be as efficient as possible. 

Americans do not have to trade clean water and clean air for 

increased natural gas supplies. The O&G industry can and 

should adopt the methane capture technologies discussed 

in this report, which are technically proven, commercially 

available, and profitable. 

Given our country’s growing reliance on natural gas and 

methane’s strong link to global warming, methane emissions 

should be controlled to the maximum extent possible. It is 

fortunate that more than 80 percent of methane emissions 

could potentially be captured with the technologies 

highlighted in this report and yield billions of dollars in 

revenues through sale of the captured methane. Under these 

circumstances, there is a compelling case for companies to 

be required to adopt the best methane capture practices as 

soon as possible, and for government at all levels to take a far 

more active role in addressing market failures and requiring 

producers to adopt best practices.

Taking these considerations into account, several policy 

options can reduce methane emissions across the natural 

gas industry nationwide. NRDC recommends adoption of the 

policies outlined below:

n	 The EPA’s proposed NSPS and air toxics standards 

provide an important starting point for the reduction 

of air pollutants from O&G operations, with substantial 

methane co-benefits. Still, there are key ways in which 

5. Conclusion and Policy Recommendations

these regulations can be improved, with robust mandates 

needed, as voluntary programs have proven insufficient. 

Federal regulations to control methane emissions 

would need to be adopted by states through their State 

Implementation Plans. The EPA should:

•	 Regulate methane directly

•	 Expand its proposal to include emission reduction

requirements for existing sources that are the main 

contributors to VOC and methane emissions from 

the oil and natural gas industry. States would then 

be required to adopt methane leakage control 

measures for existing sources through their State 

Implementation Plans

•	 Ensure coverage of all major methane emission

sources for which controls are feasible, including 

coalbed methane wells and oil wells

•	 Strengthen standards where possible. For example, the

EPA should raise standards for tank and dehydrator 

emissions reductions

•	 Strengthen required procedures where possible.

For example, the EPA should complement its Leak 

Detection & Repair program by requiring that best 

management practices be implemented, including 

process optimization and conducting more frequent 

leak surveys

n	 The EPA should continue to improve its mandatory 

greenhouse gas emissions reporting program for the O&G 

industry so that methane emission sources can be better 

identified, and opportunities for reductions can be better 

targeted. Also, the EPA should provide a more detailed 

breakdown by source of methane emissions reductions 

achieved through the Natural Gas STAR program.
PAGE 46 | Leaking Profits

n	 The EPA’s Natural Gas STAR program’s voluntary 

framework has encouraged companies to reduce 

methane emissions and document their reduction 

activities. Through Natural Gas STAR, techniques to 

reduce methane emissions have been tried and tested 

by some companies. Still, many effective reduction 

technologies have not been widely adopted by industry. 

To achieve significant industry-wide reductions, the 

most successful practices documented by the Natural 

Gas STAR program need to become mandatory. through 

EPA’s regulatory programs such as NSPS and NESHAPs. 

However, Natural Gas STAR should still play an important 

role in driving continued improvements that in turn can 

inform future revisions of EPA standards.

n	 Federal land management agencies, such as the Bureau 

of Land Management, should exercise their authority 

and responsibility to control methane waste from oil and 

gas lease operations on federal lands. Land management 

agencies should:

•	 Modernize agency policies to prevent waste of

methane resources through deployment of all 

technically and economically viable methane 

emission reduction technologies and practices, and 

to establish acceptable performance levels (i.e., 

levels of emissions beyond which production of 

mineral resources should be prohibited)

•	 Evaluate methane emission risks and reduction

opportunities as both a climate and waste problem 

through planning and environmental reviews before 

committing resources to development

•	 Not commit resources to development where

methane emissions cannot technically or 

economically be abated within acceptable 

performance levels

•	 Where lands are committed to development,

mandate specific methane reduction technologies 

and practices appropriate to the particular 

production field or geologic formation under 

consideration

•	 Shift the burden to oil and gas lessees and operators

to demonstrate, before drilling permits are approved, 

that all reasonable and prudent methane emission 

prevention technologies and practices will be used, 

with land management agencies retaining full 

authority to mandate specific methane reduction 

technologies and practices or levels of performance

n	 States should require the use of methane control 

technologies. Several gas-producing states have already 

required methane pollution reduction measures 

to protect air quality and public health, mostly for 

large emission sources or in areas of concentrated 

development. These states, including Colorado, 

Wyoming, and Montana, provide a good start and 

model for action by other states and by federal agencies. 

Exceptions to these rules should be as narrow as possible.
PAGE 47 | Leaking Profits

APPENDIX A

The tables in Appendix A provide a detailed economic summary of the 10 methane control technologies. A brief economic 

summary was also provided in Table 4. The economic analysis in this appendix is presented in a manner that facilitates a ready 

comparison among reports from various sources. Blank cells indicate insufficient data to compute values.

Where applicable, the economics of the technologies are also compared with the EPA’s estimates from its proposed NSPS 

rulemaking. However, NRDC and other environmental organizations are concerned about potential deficiencies in the EPA’s 

cost-benefit estimates of methane control technologies.172 Therefore, NRDC has not utilized the EPA’s NSPS estimates to 

inform the range of costs and benefits in this report, and instead has relied heavily on industry data and the EPA’s Natural Gas 

STAR and Methane to Markets data. 

Each line in the tables below represents a different data source or a different treatment within a source. Each line includes 

the source and year of the data (corresponding to the sources cited in the body of this report). The “Type” column describes 

any feature of the data, such as whether it was an upper bound or an average or based on a particular kind of technology. The 

next column specifies, if available, the number of devices (or wells or installations) from which an average was obtained. The 

remaining columns discuss the economics of the technologies. 

The terms used in the tables are consistent with common industry and accounting practices:

•	 Total investment: Total costs of implementing a technology; typically up-front costs, excluding ongoing operating and

maintenance expense.

•	 Annual investment expense: Effective investment cost spread out over the useful life of the investment. In a few tables, for

simplicity this is just depreciation expense, using simple depreciation with no salvage value. In other tables where more 

information is available, this includes joint depreciation and interest expenses using a capital recovery factor.

•	 O&M expense: Operating and maintenance expense for technology deployment.

•	 Total annual expense: Annual investment expense plus O&M expenses.

•	 Revenue from NG: Revenue from the sale of natural gas, obtained by multiplying gas sales volume and price.

•	 Other revenue: Revenues other than from the sale of natural gas.

•	 O&M savings: Operating and maintenance savings from technology deployment.

•	 Total revenue plus savings: Sum of revenue and any O&M savings.

•	 Payout: Period (in years) in which initial investment is paid back (i.e., total investment divided by total revenues, plus

O&M savings, less O&M costs per year).

•	 Operating profit excluding depreciation: Total revenues, plus O&M savings, less O&M costs, excluding depreciation; akin

to EBITDA (earnings before interest, taxes, depreciation and amortization). This is sometimes referred to as “profit” in 

the text. 

•	 Operating profit: Total revenues, plus O&M savings, less O&M costs, less depreciation (approximated to annual

investment expense, as above); akin to EBIT (earnings before interest and taxes).
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Table A1: Cost-effectiveness of green completions

# $ $ $ Mcf / well $ / Mcf $ / well $ / well $ / well Years $ / well $ / well

Source Year Type # wells

Total investment per well

O&M expense per well 

Total expense per well

Volume of saved NG

Price of NG

Revenue from NG

Condensate revenue

Total revenue plus savings per well

Payout

Operating profit (ex depr) per well

Operating profit per well

EPA Lessons Learned 173 2011 Purchased equip. 125 4,000a 4,850b 8,850 10,800c 4.00 43,200 7,000c 50,200 0.50d 45,350 41,350 

EPA Lessons Learned 173 2011 Rented equip. 33,000e 33,000 10,800 4.00 43,200 6,930f 50,130 immediate 50,130 17,130 

EPA174 2005 Avg. 14,000 14,000 7,000 4.00 28,000 28,000 immediate 28,000 14,000

Devon Energy 

175,176,177

2004, ’05,’07 Avg. ~400g 8,700 8,700 50,000 50,000 0.17 50,000 41,300 

BP 178,179 2005, ’07 Avg. 106 12,264 12,264 7,500 4.00 30,000 6,321 36,321 0.70 36,321 24,057 

Williams 180 2006 Avg. 1,177 14,444 14,444 22,515 4.00 90,059h 90,059 0.16 90,059 75,616 

EnCana 181 Avg. Many wells < 1.00 190 M + 

Anadarko 182 2009 Avg. 613 5.00 16,803 

ICF 183 2009 Avg. 0.25 

(EPA NSPS TSD estimates below not utilized to inform the range of costs and benefits in this report; only provided for completeness)EPA - NSPS TSD 184 2008 Min 2,418 2,418 

EPA - NSPS TSD 184 2008 Max 74,860 74,860 

EPA - NSPS TSD 184 2008 Avg. 33,237 33,237 8,258i 4.00 33,032 2,380 35,412 0.94 35,412 2,175

a Based on an investment cost of $500,000, that is spread out over 5 years and 25 well completions per year (does not take into account time value of money).b Based on annual costs of $121,250 spread out over 25 well completions per year.c Volume of saved NG based on 270,000 Mcf saved per year, and condensate revenue based on $175,000 per year, spread out over 25 well completions per year.d Initial investment of $500,000 paid back by operating profit (ex depr) of $45,350 per well x 25 wells per year.e Based on 9 days per well completion and daily costs for contracted services of $3,600 per well per day, plus $600 for initial set-up costs.f Based on 9 days per well completion, 11 barrels of condensates saved per day, valued at $70 per barrel of condensate.g Calculated from estimated average emissions per well, given that total emissions reductions was ~4.8 Bcf in 2005.h Scaled down from revenues based on a historically higher natural gas price, assumed to be $6/Mcf.i 8,258 Mcf of methane: 142.7 tons of methane; production quality natural gas is approx. 83% methane (EPA NSPS TSD page 5-16); 0.0208 tons per Mcf. This is consistent with API’s estimate of 8,400 Mcf of methane based on 1,2 Mcf/day for 7 

 days (API comments to EPA, EPA–HQ–OAR–2010–0505-4266).
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Table A2: Cost-effectiveness of plunger lift systems

# $ $ / yr Mcf / yr $ / Mcf $ / yr $ / yr $ / yr Years $ / yr $ / yr

Source Year Type # installations Total investment Annual investment 

expense

Volume of saved NG

Price of NG

Revenue from NG

O&M savings per year a

Total revenue plus savings per year

Payout

Operating profit (ex depr) per year

Operating profit per year

EPA Lessons Learned 185 2010 Min 2,600 520b 4,700 4.00 18,800 10,900 29,700 0.09 29,700 29,180 

EPA Lessons Learned 185 2010 Max 10,400 2,080 18,250 4.00 73,000 10,900 83,900 0.12 83,900 81,820 

EPA Lessons Learned 185 2010 Simple Avg. 6,500 1,300 11,475 4.00 45,900 10,900 56,800 0.11 56,800 55,500 Mobil Oil 186 1997 Avg. 19 640 4.00 2,561 2,561 2,561 BP 186,187 2007 Avg. 2,200 1,424 4.00 5,696 7,045 Amoco 188 2006 Avg. 1,177 13,000 2,600 13,167 6.00 79,000 24,000c 103,000 0.13 103,000 100,400 

a Operational savings here includes maintenance costs less savings such as chemical treatments.b Assumes lifetime of five years for all examples, uses simple depreciation.c Includes savings from avoided electricity, well workovers and chemical treatments.

Table A3: Cost-effectiveness of TEG dehydrator controls

# $ $ / yr $ / yr $ / yr Mcf / yr $ / Mcf $ / yr $ / yr Years $ / yr $ / yr

Source Year Type # devices Total investment Annual investment 

expense

O&M expense per year

Total expense per year

Volume of saved NG

Price of NG

Revenue from NG

Total revenue plus savings per year

Payout

Operating profit (ex depr) per year

Operating profit per year

EPA NG STAR 189,190 2005 Flash tank separator 5,000 1,000a 1,000 3,650 4 14,600 14,600 0.34 14,600 13,600 

EPA NG STAR 189,190 2005

Optimizing glycol circ. Rate

18,250 4 73,000 73,000 73,000 73,000 

EPA NG STAR 191 2007

Rerouting glycol skimmer gas

 1,000 200 100 300 7,665 4 30,660 30,660 0.03 30,560 30,360 

EPA NG STAR 192 2007

Installing electric pump

 7,000b 1,400 1,400 5,000c 4 20,000 20,000 0.35 20,000 18,600 

EPA NG STAR 193 2005 – 07 All four above 4 13,000 2,600 100 2,700 34,565 4 138,260 138,260 0.09 138,160 135,560 

a Assumes lifetime of five years for all examples, uses simple depreciation.b Approximate average of a range of costs from $1,400 to $13,000.c Conservative estimate based on the EPA range (360 Mcf/year to 36,000 Mcf/year).
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Table A4: Cost-effectiveness of desiccant dehydrators

# $ $ / yr Mcf $ / Mcf $ / yr $ / yr $ / yr Years $ / yr $ / yr

Source Year Type # devices Total investment Annual investment 

expense

Volume of saved NG

Price of NG

Revenue from NG

O&M savings per year

Total revenue plus savings per year

Payout

Operating profit (ex depr) per year

Operating profit per year

EPA NG STAR 194 2009 Avg. 16,000 3,200a 1,000 4 4,000 2,000 6,000 2.67 6,000 2,800 

BP 195 2007 Avg. 858 “immediate” 3,147b

a Assumes lifetime of five years, uses simple depreciation.b Based on reported profit of $27 million. Assumes a lifetime of 10 years. $3,147 is the operating profit per device per year (including annual investment expense) over the period of 10 years.

Table A5: Cost-effectiveness of replacing wet seals in centrifugal compressors with dry seals

# $ $ / yr Mcf $ / Mcf $ / yr $ / yr $ / yr Years $ / yr $ / yr

Source Year Type # devices Total investment Annual investment 

expense

Volume of saved NG

Price of NG

Revenue from NG

O&M savings per year

Total revenue plus savings per year

Payout

Operating profit (ex depr) per year

Operating profit per year

EPA Lessons Learned 196 2006 Avg. 324,000 46,129a 45,120 4 180,480 102,400 282,880 1.15 282,880 236,751

EPA NG STAR 197,198 2006 Max (savings) 324,000 46,129 100,000 4 400,000b 120,000c 520,000 0.62 520,000 473,871 

Petroleos Mexicanos 199 2008 Avg. 35,000 4 140,000 140,000+ 140,000+Targa 200 2006 Avg. 90,000 12,814 300,000 0.38d 300,000 287,186 

(EPA NSPS TSD estimates below not utilized to inform the range of costs and benefits in this report; only provided for completeness)EPA – NSPS TSD 201 2008 Processing 75,000e 10,678f 11,527g 4 46,108 88,300 134,408 0.56 134,408 123,730 

EPA – NSPS TSD 201 2008 Trans. / Storage 75,000 10,678 6,372g 88,300 88,300 0.85 88,300 77,622 

EPA – NSPS TSD 201 2008 Simple avg. 75,000 10,678 8,949 23,054 88,300 111,354 0.67 111,354 100,676 

a For annual investment expense including joint depreciation and interest expenses, assumes similar lifetimes and discount rate as in the EPA’s NSPS estimates.b Illustrative high-end estimate of natural gas savings based on the range of savings from $75,000 - $400,000.c Average maintenance and operational savings of $120,000 based on the range of savings of $100,000 - $140,000.d Average of 2 – 7 months.e The EPA reports this to be 1-3% of the total pipeline cost. This is the incremental cost of a compressor with a dry seal instead of one with a wet seal (EPA NSPS TSD, page 6-19).f The EPA assumes a 10-year lifetime and a 7% discount rate; here annual investment expense includes joint depreciation and interest expenses.g EPA NSPS TSD, page 6-20, Table 6-8; based on individual compressor emissions reductions in tons per year.
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Table A6: Cost-effectiveness of replacing rod packing in reciprocating compressors

# $ $ / yr Mcf $ / Mcf $ / yr $ / yr Years $ / yr $ / yr

Source Year Type # devices Total investment Annual investment 

expense

Volume of saved NG

Price of NG

Revenue from NG

Total revenue plus savings per year

Payout

Operating profit (ex depr) per year

Operating profit per year

EPA Lessons Learned 202 2006 Avg. 6,480a 2,493b 3,460 4 13,840 13,840 0.47 13,840 11,347

JPT 203 2008 Avg. 4,800c 1,847b 3,504d 4 14,016 14,016 0.34 14,016 12,169 

(EPA NSPS TSD estimates below not utilized to inform the range of costs and benefits in this report; only provided for completeness)EPA – NSPS TSD 204 2008 Production 6,480 2,493e 9f 4 36 36 180.00 36 (2,457)

EPA – NSPS TSD 204 2008 Gathering, Boosting 5,346 1,669e 396f 4 1,584 1,584 3.38 1,584 (85)

EPA – NSPS TSD 204 2008 Processing 4,050 1,413e 1,077f 4 4,308 4,308 0.94 4,308 2,895 

EPA – NSPS TSD 204 2008 Transmission 5,346 1,669e 1,257f 0 NA 0 (1,669)

EPA – NSPS TSD 204 2008 Storage 7,290 2,276e 1,263f 0 NA 0 (2,276)EPA – NSPS TSD 204 2008 Simple avg. 5,702 1,904 296 4 1,186 1,186 4.81 1,186 (718)

a Cost of replacing rod packing for four cylinders (as per EPA TSD estimate of average number of reciprocating compressor cylinders in the production sector, Table 6-2), at $1,620 per cylinder. b For annual investment expense including joint depreciation and interest expenses, assumes similar lifetimes and discount rate as in the EPA’s NSPS estimate for reciprocating compressors in the production sector, i.e., same capital recovery 

factor (EPA NSPS TSD Table 6-7 and page 6-16).

c Cost of replacing rod packing for four cylinders (as per EPA TSD estimate of average number of reciprocating compressor cylinders in the production sector, Table 6-2), at $1,200 per cylinder. d Multiplying estimated emissions savings as reported by sources by four, to account for savings from four cylinders.e The EPA annual investment expense estimates include joint depreciation and interest expenses, but uses slightly different capital recovery factors for different kinds of devices (EPA NSPS TSD Table 6-7 and page 6-16).f EPA NSPS TSD, page 6-15, Table 6-6; based on individual compressor emissions reductions in tons per year.
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Table A7: Cost-effectiveness of replacing high-bleed pneumatic controllers with low-bleed pneumatic controllers

# $ $ / yr Mcf $ / Mcf $ / yr $ / yr $ / yr Years $ / yr $ / yr

Source Year Type # devices

Total investment cost

Annual investment expense

Volume of saved NG

Price of NG

Revenue from NG

O&M savings per year

Total revenue plus savings per year

Payout

Operating profit (ex depr) per year

Operating profit per year

EPA 205,206,207 2005 Avg. 350a 50b 180c 4 720 1,100 1,820 0.19 1,820 1,784 

EPA Lessons Learned 208 2006 Avg. 275d 39b 125e 4 500 50 550 0.50 550 511

BP 209 2005 Avg. 11,500 174f 25b 296g 4 1,183 726 1,909 0.09 1,909 1,884 

(EPA NSPS TSD estimates below not utilized to inform the range of costs and benefits in this report; only provided for completeness)EPA - NSPS TSD 210 2008 Min 158 23h

EPA - NSPS TSD 210 2008 Max 1,852 264 

EPA - NSPS TSD 210 2008 Avg. 165 24 375i 4 1,500 1,500 0.11 1,500 1,477 

a Based on incremental cost of fitting low-bleed devices instead of low-bleed devices, for all lines.b For annual investment expense including joint depreciation and interest expenses, assumes similar lifetimes and discount rate as in the EPA’s NSPS estimates.c Based on average natural gas savings of 0.5 Mcf/day (as reported in sources).d Average of $210 and $340 per device.eAverage of 50 and 200 Mcf/year.f Assumes half of replacement cost.g 11,500 wells saved 3.4 Bcf/year.h The EPA assumes a lifetime of 10 years and a discount rate of 7% (NSPS TSD page 5-16, 5-17); here annual investment expense includes joint depreciation and interest expenses.i Using the average value of dollar savings (NSPS TSD page 5-16); calculated natural gas volume is consistent with TSD value quoted.
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Table A8: Cost-effectiveness of replacing high-bleed pneumatic controllers with instrument- air pneumatic controllers

# $ $ / yr $ / yr $ / yr Mcf $ / Mcf $ / yr $ / yr Years $ / yr $ / yr

Source Year Type # devices Total investment Annual investment 

expense

O&M expense per year

Total expense per year

Volume of saved NG

Price of NG

Revenue from NG

Total revenue plus savings per year

Payout

Operating profit (ex depr) per year

Operating profit per year

EPA NG STAR 211,212 2005 Avg. 10,000 1,400a 7,500b 8,900 5,400 4 21,600 21,600 0.70 - 2.00c 14,100 12,700 

EPA Lessons Learned 213 2006 Avg. 60,000 8,500a 17,700b 26,200 20,000 4 80,000 80,000 0.96 62,300 53,800

(EPA NSPS TSD estimates below not utilized to inform the range of costs and benefits in this report; only provided for completeness)EPA - NSPS TSD 214 2008 Small 16,972 2,416d 1,334 11,090e 871 4 3,484 3,484 NA (5,190) (7,606)

EPA - NSPS TSD 214 2008 Med. 73,531 10,469 4,333 36,877 3,658 4 14,632 14,632 NA (11,776) (22,245)

EPA - NSPS TSD 214 2008 Large 135,750 19,328 5,999 80,515 10,161 4 40,644 40,644 NA (20,543) (39,871)EPA - NSPS TSD 214 2008 Simple 

avg. 75,418 10,738 3,889 42,827 4,897 4 19,587 19,587 NA (12,503) (23,241)

a For annual investment expense including joint depreciation and interest expenses, assumes similar lifetimes and discount rate as in the EPA’s NSPS estimates.b Includes both labor and operational costs such as electrical power (unlike EPA costs in same column).c Range between calculated value and reported value.d EPA assumes a 10-year life, and a 7% discount rate; here annual investment expense includes joint depreciation and interest expenses.e The total expense includes capital, labor and electrical power.
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Table A9: Cost-effectiveness of installing vapor recovery units

# $ $ / yr $ / yr $ / yr Mcf $ / Mcf $ / yr $ / yr Years $ / yr $ / yr

Source Year Type # devices Total investment Annual investment 

expense

O&M expense per year

Total expense per year

Volume of saved NG

Price of NG

Revenue from NG

Total revenue plus savings per year

Payout

Operating profit (ex depr) per year

Operating profit per year

EPA NG STAR 215 2010 Small 35,738a 3,924b 7,367 11,291 4,566 4 18,262c 18,262 3.28 10,895 6,972 

EPA NG STAR 215 2010 Med. 55,524 6,096b 10,103 16,199 18,262 4 73,048 73,048 0.88 62,945 56,849 

EPA NG STAR 215 2010 Large 103,959 11,414b 16,839 28,253 91,311 4 365,242 365,242 0.30 348,403 336,990 EPA NG STAR 215 2010 Simple 

avg. 65,074 7,145b 11,436 18,581 38,046 4 152,184 152,184 0.46 140,748 133,603 

Anadarko 216 1999 Avg. 300 4,167 

ConocoPhillips 217 Avg. 9 79,167 8,692b 0.33 252,000 243,308 

Chevron 218 1996 Avg. 8 <1 

(EPA NSPS TSD estimates below not utilized to inform the range of costs and benefits in this report; only provided for completeness)EPA – NSPS TSD 219 2008 Avg. 98,186 10,780d 9,367 20,147 291 4 1,164 1,164 NA (8,203) (18,983)

a This includes capital cost and installation cost equal to 75% of the capital cost.b For annual investment expense including joint depreciation and interest expenses, assumes similar lifetimes and discount rate as in the EPA’s NSPS estimates.c Scaled down from savings based on a historically higher natural gas price of $6.22/Mcf.d EPA assumes a 15-year life and a 7% discount rate; here annual investment expense includes joint depreciation and interest expenses.
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Table A10: Cost-effectiveness of leak monitoring and repair systems

# $/ yr $ / yr $ / yr Mcf $ / Mcf $ / yr $ / yr Years $ / yr $ / yr

Source Year Type # devices

Total investment per year

O&M expense per year

Total expense per year

Volume of saved NG

Price of NG

Revenue from NG

Total revenue plus savings per year

Payout

Operating profit (ex depr) per year

Operating profit per year

EPA Lessons Learned 220 2003 Gas process- ing plants 59,000a 32,000b 91,000 86,500c 4 346,000 346,000 0.19 314,000 255,000

EPA Lessons Learned 221 2003 Compressor stations 26,200 26,200 29,400 4 117,600 117,600 0.22 117,600 91,400

Methane to Markets 222 2009 Valves 130 2,895 4 11,580 11,580 likely small likely positive 

Methane to Markets 222 2009 Connectors 10 3,482 4 13,928 13,928 likely small likely positive 

Methane to Markets 222 2009 Open ended lines 60 2,320 4 9,280 9,280 likely small likely positive Methane to Markets 222 2009 Simple avg. 67 2,899 4 11,596 11,596 likely small likely positive Canadian experience 223 2005 Avg. small positive 

(EPA NSPS TSD estimates below not utilized to inform the range of costs and benefits in this report; only provided for completeness)EPA - NSPS TSD 224 2008 Valves 18,529d incl. in total 34,608 1,060d 4 4,241 4,241 NA negative (30,366)

EPA - NSPS TSD 224 2008 Connectors 9,991 incl. in total 25,622 515 4 2,061 2,061 NA negative (23,561)

EPA - NSPS TSD 224 2008 Pressure Re- lief Devices 101,820 incl. in total 40,372 160 4 639 639 NA negative (39,734)

EPA - NSPS TSD 224 2008 Open ended lines 12,280 incl. in total 26,200 693 4 2,772 2,772 NA negative (23,428)

EPA - NSPS TSD 224 2008 Simple avg. 35,655 incl. in total 31,700 607 4 2,428 2,428 NA negative (29,272)

a Average of $39,000 and $78,000 for repairs annually.b Average of $14,000 and $50,000 for leak screening and measurement annually.c Average of 45,000 and 128,000 Mcf/year per gas plant.dAverage of values from Tables 8-14, 8-15 and 8-17. Table 8-16 data was not included as that was only incremental cost data.
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APPENDIX B: LIST OF ACRONYMS

API American Petroleum Institute

AQ Air Quality

BACT Best Available Control Technology

BAT Best Available Technology

bbl Barrels (equivalent to 42 gallons)

Bcf Billion standard cubic feet

Bcf/year Billion standard cubic feet per year

BMP Best Management Practices

bopd

BTU

Barrels of oil per day

British Thermal Unit

CDA Concentrated Development Area

CO2 Carbon Dioxide

CO2

e Carbon Dioxide equivalent

DEG Diethylene Glycol

DOE U.S. Department of Energy

E&P Exploration & Production

EIA U.S. Energy Information Administration

EPA U.S. Environmental Protection Agency

GRI

GWP

Gas Research Institute

Global Warming Potential

HAPs Hazardous Air Pollutants

HFCs Hydrofluorocarbons

IPCC Intergovernmental Panel on Climate Change

JPAD

KWh

Jonah-Pinedale Anticline Development Area

Kilowatt-hour

LAER Lowest Achievable Emission Rate

LDAR Leak Detection & Repair

MEG Ethylene Glycol

Mt Metric ton (equivalent to 1.102 short tons)

MMt Million Metric tons

MMtCO2

e Million Metric tons of Carbon Dioxide equivalent

Mcf Thousand standard cubic feet

MMcfd Million standard cubic feet per day

NAAQS

NESHAPs

National Air Ambient Air Quality Standards

National Emission Standards for Hazardous Air Pollutants

NOx

NPV

Nitrogen Oxides

Net Present Value

NRDC

NSPS

Natural Resources Defense Council

New Source Performance Standards

O&G

O&M

Oil & Gas

Operations & Maintenance

P&A

PM

PROs

Plug & Abandonment

Particulate Matter

Partnership Reduction Opportunities

PRV Pressure Relief Valve

psi Pounds per square inch

REC Reduced Emission Completion

scf Standard cubic feet

scfm Standard cubic feet per minute

TEG Triethylene Glycol

tpy

TREG

Tons per year

Tetraethylene Glycol

TSD Technical Support Document

TWG Technical Work Group

U.S. United States

VOCs Volatile Organic Compounds

VRU Vapor Recovery Unit

WCI Western Climate Initiative

WGA Western Governors Association

WRAP Western Regional Air Partnership
PAGE 57 | Leaking Profits

Table C1: Natural Gas System Methane Emission Sources

2009 Natural Gas Systems Methane Emissions Technology Options Covered in Paper Percent of overall 

emissions

Bcf Bcf %

Production 464

Well Completion, Workovers 68.26 No. 1 Green Completions 10%

Well Clean Ups (Low pressure gas wells) 236.47 No. 1 & 2 Green Completions and Plunger Lifts 33%

Dehydrator Vents 5.81 No. 3 & 4 Dehydrator Controls 1%

Reciprocating Compressors 4.33 No. 6 Improved Compressor Maintenance 1%

Pneumatic Controllers 62.92 No. 7 Low -Bleed or No-Bleed Controllers 9%

Pipeline Emissions 0.15 No. 8 Pipeline Maintenance and Repair 0%

Tank Venting 7.04 No. 9 Vapor Recovery Units 1%

Controlled Tank Vents 1.41 0%

Heaters 1.83 0%

Separators 5.85 1%

Vessel & Compressor Blowdown & 

Mishaps 0.29 0%

Compressor Starts 0.31 0%

Coal Bed Methane 3.59 1%

Engine & Turbine Exhaust 14.35 2%

Pump Emissions 17.18 2%

Offshore 15.67 2%

Fugitive Emissions 18.28 No. 10 Leak Monitoring and Repair 3%

Subtotal 463.73

Subtotal of Emissions Controllable 

by the 10 Technologies 403.26

Processing 48

Dehydrator Vents 1.39 No. 3 & 4 Dehydrator Controls 0%

Centrifugal Compressors Wet Seals 12.12 No. 5 Dry Seal Systems 2%

Centrifugal Compressors Dry Seals 1.28 0%

Reciprocating Compressors 19.93 No. 6 Improved Compressor Maintenance 3%

Pneumatic Controllers 0.10 No. 7 Low -Bleed or No-Bleed Controllers 0%

Pipeline Emissions 1.17 No. 8 Pipeline Maintenance and Repair 0%

Tank Venting 1.17 No. 9 Vapor Recovery Units 0%

Engine & Turbine Exhaust 8.64 1%

Acid Gas Removal Vents 0.65 0%

Pump Emissions 0.23 0%

Fugitive Emissions 1.67 No. 10 Leak Monitoring and Repair 0%

Subtotal 48.35

Subtotal of Emissions Controllable 

by the 10 Technologies 37.54

APPENDIX C : METHANE EMISSION SOURCE DETAIL
PAGE 58 | Leaking Profits

TRANSMISSION 129

Dehydrator Vents 0.34 No. 3 & 4 Dehydrator Controls 0%

Centrifugal Compressors Wet Seals 14.42 No. 5 Dry Seal Systems 2%

Centrifugal Compressors Dry Seals 0.98 0%

Reciprocating Compressors 51.25 No. 6 Improved Compressor Maintenance 7%

Pneumatic Controllers 13.93 No. 7 Low -Bleed or No-Bleed Controllers 2%

Pipeline Emissions 17.35 No. 8 Pipeline Maintenance and Repair 2%

Tank Venting 1.71 No. 9 Vapor Recovery Units 0%

Engine & Turbine Exhaust 13.71 2%

Fugitive Emissions 15.18 No. 10 Leak Monitoring and Repair 2%

Subtotal 128.87

Subtotal of Emissions Controllable 

by the 10 Technologies 114.17

Distribution 74

Pipeline Emissions 0.13 No. 8 Pipeline Maintenance and Repair 0%

Fugitive Emissions (Pipeline and Meter 

Leaks) 71.55 No. 10 Leak Monitoring and Repair 10%

Pressure Relief Valves & Mishaps 

(Dig-ins) 2.15 0%

Subtotal 73.84

Subtotal of Emissions Controllable 

by the 10 Technologies 71.69

TOTAL 715

Total of Emissions Controllable by 

the 10 Technologies 627 88%

Other Emissions 88 12%

Source: U.S. EPA 2011 Greenhouse Gas Inventory Conversion: Gg/19.26=Bcf 

Table C2: Petroleum System Methane Emission Sources

2009 PETROLEUM SYSTEM METHANE EMISSIONS TECHNOLOGY OPTIONS COVERED IN PAPER PERCENT OF TOTAL

EMISSIONS

Bcf Bcf %

Production 75

Pneumatic Controller 21.75 No. 7 Low -Bleed or No-Bleed Controllers 29%

Tank Venting 11.01 No. 9 Vapor Recovery Units 14%

Fugitive Emissions 37.33 No. 10 Leak Monitoring and Repair 49%

Combustion and Process Upsets 4.88 6%

Subtotal 74.97

Subtotal of Emissions Controllable 

by the 10 Technologies 70.09

Transmission 0 0%

Refining 1 2%

Total 76

Total of Emissions Controllable by 

the 10 Technologies 92%

Other emissions 8%

Source: U.S. EPA 2011 Greenhouse Gas Inventory Conversion: Gg/19.26=Bcf 

Table C1: Natural Gas System Methane Emission Sources (Continued)
PAGE 59 | Leaking Profits

Endnotes

1 U.S. Energy Information Administration, Natural Gas Gross 

Withdrawals and Production, 2009 data. Available at http://

www.eia.gov/dnav/ng/ng_prod_sum_dcu_NUS_a.htm.

2 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

3 Operator is the term used throughout this report, and by 

industry, to refer to the companies that operate oil and gas 

fields, processing, and transportation equipment.

4 U.S. EPA, Recommended Technologies and Practices, 2011 data. 

Available at http://www.epa.gov/gasstar/tools/recommended.

html. As of October 26, 2011, there were 95 technologies and 

practices listed that are known to be effective in reducing 

methane emissions from the O&G industry.

5 Government Accountability Office, Opportunities Exist to 

Capture Vented and Flared Natural Gas, Which Would Increase 

Royalty Payments and Reduce Greenhouse Gases, Washington 

D.C., October 2010; GAO-11-34.

6 U.S. EPA Greenhouse Gas Equivalencies Calculator, 2011. 

Available at http://www.epa.gov/cleanenergy/energyresources/calculator.html#results.

7 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

8 U.S. EPA, Oil and Gas Sector: New Source Performance 

Standards and National Emission Standards for Hazardous Air 

Pollutants Reviews, August 23, 2011; Federal Register, v. 76, no. 

163 (76 FR 52738), EPA Docket No. EPA–HQ–OAR–2010–0505, 

FRL–9448–6. Available at http://www.epa.gov/airquality/

oilandgas/index.html.

9 This report is not intended to be a critique of the proposed 

NSPS; NRDC’s comments on EPA’s NSPS proposal may be 

obtained from the regulatory docket, available at www.

regulations.gov: NRDC and other environmental organizations, 

Comments on New Source Performance Standards and 

National Emission Standards for Hazardous Air Pollutants 

Reviews, Proposed Rule, November 30, 2011, EPA Docket 

No. EPA-HQ-OAR-2010-0505, Document ID No. EPA-HQOAR-2010-0505-4240. NRDC also recommends that the National 

Emission Standards for Hazardous Air Pollutants (NESHAPs) be 

strengthened. Comments on the EPA’s NESHAPs proposal are 

available at Document ID No. EPA-HQ-OAR-2010-0505-4457.

10 Burcik, E.J., Properties of Petroleum Reservoir Fluids, 1979.

11 Encana Oil & Gas USA spokesperson, quoted in the Star-Tribune 

Energy Reporter, October 11, 2010:“[I]t is in our own interest to 

reduce emissions for a variety of reasons. One being it keeps the 

product we produce in the revenue stream.”

12 American Petroleum Institute (API) and the International 

Petroleum Industry Environmental Conservation Association 

(IPIECA), Oil and Natural Gas Industry Guidelines for 

Greenhouse Gas Reduction Projects, March 2007, prepared by 

URS Corporation concludes on page 18 that “Companies and 

investors operate under capital constrains and the estimated 

financial returns of such GHG reduction projects may not justify 

diverting capital from other higher return or more strategic 

initiatives.”

13 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

14 Howarth, R. et al., Methane Emissions from Natural Gas 

Systems, Background Paper Prepared for the National Climate 

Assessment (reference number 2011-0003), February 25, 2012. 

Available at http://www.eeb.cornell.edu/howarth/Howarth%20

et%20al.%20--%20National%20Climate%20Assessment.pdf

This paper notes that more recent research suggests that a 

global warming potential value for methane of 33 times that 

of CO2 on a 100-year time frame may be appropriate and on 

shorter time frames of 20 years or less, that methane may be 105 

times more potent.

15 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2008), April 2010, page 3-47; U.S. EPA # 430-R-10-

006.

16 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2008), April 2010, page A-144, Table A-118: 2008 

Data and CH4 Emissions (Mg) for the Natural Gas Production 

Stage.

17 U.S. EPA, Natural Gas STAR Program, Recommended 

Technologies and Practices, Wells. Available at http://www.epa.

gov/gasstar/tools/recommended.html.

18 Devon Energy, U.S. EPA Natural Gas Star 2009 workshop 

presentation, slides 3 and 13. 6,300 Mcf =11.4 Bcf / 1,798 wells.

19 U.S. EPA, Natural Gas STAR Program, Recommended 

Technologies and Practices, Wells. Available at http://www.epa.

gov/gasstar/tools/recommended.html, and specifically http://

www.epa.gov/gasstar/documents/workshops/pennstate2009/

robinson1.pdf.

20 These data are consistent with the unconventional gas well 

completion and workover data presented in: U.S. EPA, Proposed 

Mandatory Reporting of Greenhouse Gases: Petroleum and 

Natural Gas Systems (Subpart W), Technical Support Document, 

2009; Docket EPA-HQ-OAR-2009-0923.

21 U.S. EPA, Methane Emissions from the Natural Gas Industry, 

Project Summary, June 1997; EPA/600/SR-96/080.

22 U.S. EPA, Proposed Mandatory Reporting of Greenhouse Gases: 

Petroleum and Natural Gas Systems (Subpart W), Technical 

Support Document, 2009; Docket EPA-HQ-OAR-2009-0923:“...

emissions estimates from the EPA/GRI Study are outdated and 

potentially understated for some emission sources.”

23 U.S. EPA, Proposed Mandatory Reporting of Greenhouse 

Gases: Petroleum and Natural Gas Systems (Subpart W), 

Technical Support Document, 2009, page 23; Docket EPA-HQOAR-2009-0923.

24 U.S. EPA, Proposed Mandatory Reporting of Greenhouse Gases: 

Petroleum and Natural Gas Systems (Subpart W), Technical 

Support Document, 2009, Table 1 at page 8 and Appendix B, 

Docket EPA-HQ-OAR-2009-0923.

25 United States Federal Register, 75 FR 18621.

26 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

27 U.S. EPA, Proposed Mandatory Reporting of Greenhouse Gases: 

Petroleum and Natural Gas Systems (Subpart W), Technical 

Support Document, 2009, Docket EPA-HQ-OAR-2009-0923.

28 Chambers, A.K. et al., DIAL Measurements of Fugitive Emissions 

from Natural Gas Plants and the Comparison with Emission 

Factor Estimates, 2006, found fenceline measurements of 

Canadian natural gas processing plants to be roughly an order 

of magnitude higher than estimated emissions of volatile 

organic compounds and benzene.

29 U.S. EPA, Natural Gas STAR Program. Available at http://www.

epa.gov/gasstar/.

30 U.S. EPA, Methane to Markets, Reducing Emissions, Increasing 

Efficiency, Maximizing Profits, 2008. Available at www.epa.gov/

gasstar/international/index.html.
PAGE 60 | Leaking Profits

31 “Demonstrated solutions” means the technology has been 

developed, tested, and is available on the market for purchase 

and installation.

32 U.S. EPA, Oil and Gas Sector: New Source Performance 

Standards and National Emission Standards for Hazardous Air 

Pollutants Reviews, August 23, 2011, Federal Register, v. 76, no. 

163 (76 FR 52738), EPA Docket No. EPA–HQ–OAR–2010–0505, 

FRL–9448–6. Available at http://www.epa.gov/airquality/

oilandgas/index.html.

33 NRDC does not accept these EPA estimates, as discussed in 

our comments on the proposed NESHAPs: NRDC and other 

environmental organizations, Comments on New Source 

Performance Standards and National Emission Standards for 

Hazardous Air Pollutants Reviews, Proposed Rule, November 

30, 2011, EPA Docket No. EPA-HQ-OAR-2010-0505, Document 

ID No. EPA-HQ-OAR-2010-0505-4457. Available at www.

regulations.gov. 

34 Campbell, J.M., Analysis and Management of Petroleum 

Investments: Risk, Taxes, and Time, John Campbell and Co., 

1987.

35 The revenue stream is calculated using constant dollars over 

the payout period because the payout periods are short for 

the emission control alternatives examined in this report. 

Discount rates will vary widely for O&G Operators and will 

add unnecessary complexity to a simplified analysis that seeks 

to show revenue generated by selling methane will exceed 

the cost of methane controls. For the purposes of this report, 

profit computations do not include the opportunity cost of 

capital. While some companies may assert that they have 

more profitable places to spend their money than methane 

emission control, it is not possible for this report to evaluate 

the opportunity cost of capital because it will vary widely 

across oil and gas companies, depending on their portfolio of 

opportunities in the United States and abroad. The purpose of 

this report is to identify methane control opportunities that are 

commonly robust economic opportunities, and not to provide a 

company-specific economic analysis.

36 U.S. EPA, Oil and Gas Sector: New Source Performance 

Standards and National Emission Standards for Hazardous Air 

Pollutants Reviews, August 23, 2011; Federal Register, v. 76, No. 

163 (76 FR 52738), EPA Docket No. EPA–HQ–OAR–2010–0505, 

FRL–9448–6. Available at http://www.epa.gov/airquality/

oilandgas/index.html.

37 NRDC and other environmental organizations, Comments on 

New Source Performance Standards and National Emission 

Standards for Hazardous Air Pollutants Reviews, Proposed Rule, 

November 30, 2011, EPA Docket No. EPA-HQ-OAR-2010-0505, 

Document ID No. EPA-HQ-OAR-2010-0505-4240 (NSPS) and 

Document ID No. EPA-HQ-OAR-2010-0505-4457 (NESHAPs). 

Available at www.regulations.gov..

38 Condensates are low density, high quality API gravity liquid 

hydrocarbons. The API gravity of condensate is typically 50 

degrees to 120 degrees. Depending on the gas composition, 

hydrocarbons may condense from a gas to a liquid under 

certain temperature and pressure conditions. Dry gas is routed 

to the sales line, and liquid condensate is collected in tanks and 

sold. 

39 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

40 U.S. EPA, Cost-Effective Methane Emissions Reductions for 

Small and Midsize Natural Gas Producers, Journal of Petroleum 

Technology, June 2005.

41 U.S. EPA, Regulatory Impact Analysis, Proposed New Source 

Performance Standards and Amendments to the National 

Emissions Standards for Hazardous Air Pollutants for the Oil 

and Natural Gas Industry, July 2011, page 3-21. Available at 

http://www.epa.gov/airquality/oilandgas/index.html.

42 U.S. EPA Natural Gas STAR, Proposed Mandatory Reporting 

of Greenhouse Gases: Petroleum and Natural Gas Systems 

(Subpart W), Technical Support Document, 2009, page 87, 

Docket EPA-HQ-OAR-2009-0923. 

43 U.S. EPA Natural Gas STAR, Reduced Emissions Completions 

for Hydraulically Fractured Natural Gas Wells, Lessons Learned 

from Natural Gas STAR Partners, 2011.

44 U.S. EPA, Natural Gas STAR Program Accomplishments, 2009. 

Available at http://www.epa.gov/gasstar/documents/ngstar_

accomplishments_2009.pdf. Total sector reductions (2008) = 

89.3 Bcf of which 50 percent are the result of RECs (50% of 89.3 

Bcf = 45 Bcf).

45 Colorado Oil and Gas Conservation Commission, Rule § 805(b)

(3).

46 Fort Worth Texas, Ordinance No. 18449-02-2009.

47 Montana Administrative Rules § 17.8.1711.

48 Wyoming Oil and Gas Production Facilities, Chapter 6, Section 

2, Permitting Guidance, March 2010.

49 American Petroleum Institute (API), Comments to U.S. EPA on 

Docket ID No. EPA-HQ-OAR-2010-0505, November 30, 2011, 

Page 94.

50 U.S. EPA, Standards of Performance for New Stationary Sources: 

Oil and Natural Gas Production and Natural Gas Transmission 

and Distribution; National Emission Standards for Hazardous 

Air Pollutants From Oil and Natural Gas Production Facilities; 

and National Emission Standards for Hazardous Air Pollutants 

From Natural Gas Transmission and Storage Facilities, 2011, 

page 123 of 604; Docket ID No. EPA-HQ-OAR-2010-0505. 

51 U.S. EPA, Standards of Performance for New Stationary Sources: 

Oil and Natural Gas Production and Natural Gas Transmission 

and Distribution; National Emission Standards for Hazardous 

Air Pollutants From Oil and Natural Gas Production Facilities; 

and National Emission Standards for Hazardous Air Pollutants 

From Natural Gas Transmission and Storage Facilities, 2011, 

page 125 of 604; Docket ID No. EPA-HQ-OAR-2010-0505. 

52 U.S. EPA Natural Gas STAR, Reduced Emissions Completions 

for Hydraulically Fractured Natural Gas Wells, Lessons Learned 

from Natural Gas STAR Partners, 2011.

53 U.S. EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005. 

54 U.S. EPA Natural Gas STAR, Green Completions, PRO Fact Sheet 

No. 703, September 2004.

55 ICF Incorporated, Technical Assistance for the Draft 

Supplemental Generic EIS: Oil, Gas and Solution Mining 

Regulatory Program, prepared for New York State, August 5, 

2009.

56 U.S. EPA, ExxonMobil Production Company, and American 

Petroleum Institute, Green Completions, Lessons Learned from 

Natural Gas STAR, Producers Technology Transfer Workshop, 

September 21, 2004.

57 O’Connell, S., Devon Energy, EPA Natural Gas STAR Program 

Presentation, March 2007.
PAGE 61 | Leaking Profits

58 U.S. EPA and Devon Energy, Reduced Emissions Completions 

(Green Completions), Natural Gas STAR Producers Technology 

Transfer Workshop, Casper, Wyoming, August 30, 2005. Profit 

was based on gas at $1.99 Mcf and condensate at $22/bbl. Gas 

and condensate prices are substantially higher in 2010; thus, 

this is a very conservative profit estimate. 

59 Smith, G.R., BP America Production Company, Natural Gas 

Industry Green House Gas Control & Business Opportunity 

Presentation, 2007.

60 The Williams Companies, Reducing Methane Emissions During 

Completion Operations – Economics Volume Recovered, 

Williams Production RMT Piceance Basin Operations, Natural 

Gas Star Producers Technology Transfer Workshop, September 

11, 2007.

61 U.S. EPA and ICF International, Methane’s Role in Promoting 

Sustainable Development in the Oil and Natural Gas Industry, 

2009.

62 U.S. EPA Natural Gas STAR, Reduced Emission Completions/

Plunger Lift and Smart Automation, Methane to Markets, Oil & 

Gas Subcommittee Technology Transfer Workshop, Monterrey, 

Mexico, January, 2009. Anadarko based the gas value at $5/Mcf.

63 BP, Case Study: North America Gas Strategic Performance 

Unit’s Green Completion’s Well Flaring Reductions Program, 

downloaded April 2010. Available at www.bp.com.

64 U.S. EPA, Cost-Effective Methane Emissions Reductions for 

Small and Midsize Natural Gas Producers, Journal of Petroleum 

Technology, June 2005.

65 Colorado Oil and Gas Conservation Commission, Rule § 805(b)

(3) (A) and (C).

66 Bondurant, A.V., Dotson, B.D., Oyewole, P.O., BP America, 

Getting the Last Gasp: Deliquification of Challenging Gas Wells, 

International Petroleum Technology Conference (IPTC), Paper 

No. 11651, December 2007.

67 Schmitz, R., and Steele, G., VaporTech Energy Services, Inc., 

Combining Plunger Lift and Compression to Lift Liquids in Low 

Rate Gas Wells, Canadian International Petroleum Conference, 

Calgary Alberta, SPE Paper No. 200-159, June 2006. 

68 U.S. EPA Natural Gas STAR, Reduced Emission Completions/

Plunger Lift and Smart Automation, Methane to Markets, Oil & 

Gas Subcommittee Technology Transfer Workshop, Monterrey, 

Mexico, January 2009.

69 Bondurant, A.V., Dotson, B.D., Oyewole, P.O., BP America, 

Getting the Last Gasp: Deliquification of Challenging Gas Wells, 

International Petroleum Technology Conference (IPTC), Paper 

No. 11651, December 2007.

70 U.S. EPA Natural Gas STAR, Installing Plunger Lift Systems in 

Gas Wells, Lessons Learned from Natural Gas STAR Partners, 

2006.

71 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

72 U.S. EPA Natural Gas STAR, Installing Plunger Lift Systems in 

Gas Wells, Lessons Learned from Natural Gas STAR Partners, 

2006.

73 Ibid.

74 Ibid.

75 U.S. EPA Natural Gas STAR, Reduced Emission Completions/

Plunger Lift and Smart Automation, Methane to Markets, Oil & 

Gas Subcommittee Technology Transfer Workshop, Monterrey, 

Mexico, January 2009.

76 Schneider, T.S., and Mackey, V., Conoco, Inc., Plunger Lift 

Benefits Bottom Line for a Southeast New Mexico Operator, 

Society of Petroleum Engineers, Paper No. 59705-MS, 2000.

77 U.S. EPA Natural Gas STAR, Installing Plunger Lift Systems in 

Gas Wells, Lessons Learned from Natural Gas STAR Partners, 

2006.

78 O’Connell, S., Devon Energy, EPA Natural Gas STAR Program 

Presentation, March 2007.

79 Gantner, B., ConocoPhillips, Testimony to New Energy Economy 

Petition to the New Mexico Environmental Improvement Board, 

New Mexico Oil and Gas Association, Notice of Intent to Present 

Technical Testimony in the Matter of the Petition for Hearing 

to Adopt New Regulations and to Amend Various Sections of 

20.2.1, 20.2.2, 20.2.70, and 20.2.72 NMAC Statewide Cap on 

Greenhouse Gas Emissions, August 2010.

80 U.S. EPA Natural Gas STAR, Installing Plunger Lift Systems in 

Gas Wells, Lessons Learned from Natural Gas STAR Partners, 

2006.

81 Gas Processors Suppliers Association (GPSA), Gas Processors 

Suppliers Association Handbook, Tenth Edition 1987, revised 

1994.

82 U.S. EPA Natural Gas STAR, Reroute Glycol Skimmer Gas, PRO 

Fact Sheet No. 201, 2004.

83 U.S. EPA Natural Gas STAR, Replacing Gas-Assisted Glycol 

Pumps with Electric Pumps, Lessons Learned from Natural Gas 

STAR Partners, 2009.

84 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

85 U.S. EPA Natural Gas STAR, Replacing Gas-Assisted Glycol 

Pumps with Electric Pumps, Lessons Learned from Natural Gas 

STAR Partners, 2009.

86 U.S. EPA Natural Gas STAR, Optimize Glycol Circulation and 

Install Flash Tank Separators in Glycol Dehydrators, Lessons 

Learned from Natural Gas STAR Partners, 2009.

87 U.S. EPA Natural Gas STAR, Natural Gas Dehydration, Natural 

Gas STAR Producers Technology Transfer Workshop, Durango, 

Colorado, September 13, 2007.

88 The wide range in methane capture opportunity is a function of 

the dehydrator size, and how efficiently the operator previously 

optimized the glycol circulation rate.

89 U.S. EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005.

90 U.S. EPA Natural Gas STAR, Natural Gas Dehydration, Natural 

Gas STAR Producers Technology Transfer Workshop, Durango, 

Colorado, September 13, 2007.

91 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

92 Under section 112(d) of the Clean Air Act.

93 U.S. EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005.

94 U.S. EPA Natural Gas STAR, Natural Gas Dehydration, Natural 

Gas STAR Producers Technology Transfer Workshop, Durango, 

Colorado, September 13, 2007.

95 U.S. EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005.
PAGE 62 | Leaking Profits

96 U.S. EPA Natural Gas STAR, Optimize Glycol Circulation and 

Install Flash Tank Separators in Glycol Dehydrators, Lessons 

Learned from Natural Gas STAR Partners, 2009.

97 Hygroscopic means readily absorbs moisture.

98 U.S. EPA Natural Gas STAR, Replacing Glycol Dehydrators with 

Desiccant Dehydrators, Lessons Learned from Natural Gas STAR 

Partners, 2009.

99 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

100 U.S. EPA, Cost-Effective Methane Emissions Reductions for 

Small and Midsize Natural Gas Producers, Journal of Petroleum 

Technology, June 2005.

101 U.S. EPA Natural Gas STAR, Replacing Glycol Dehydrators with 

Desiccant Dehydrators, Lessons Learned from Natural Gas STAR 

Partners, 2006. 

102 Ibid. 

103 U.S. EPA Natural Gas STAR, Natural Gas Dehydration, Natural 

Gas STAR Producers Technology Transfer Workshop, Durango, 

Colorado, September 13, 2007.

104 U.S. EPA Natural Gas STAR, Replacing Glycol Dehydrators with 

Desiccant Dehydrators, Lessons Learned from Natural Gas STAR 

Partners, 2009.

105 Smith, G.R., BP America Production Company, Natural Gas 

Industry Green House Gas Control & Business Opportunity 

Presentation, 2007.

106 U.S. EPA Natural Gas STAR, Reducing Methane Emissions 

from Reciprocating and Centrifugal Compressors, Methane 

to Markets, Oil & Gas Subcommittee Technology Transfer 

Workshop, 2009.

107 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

108 U.S. EPA Natural Gas STAR, Replacing Wet Seals with Dry Seals 

in Centrifugal Compressors, 2009; EPA 430-B-03-012.

109 Ibid.

110 Ibid.

111 U.S. EPA, Replacing Wet Seals with Dry Seals in Centrifugal 

Compressors, Lessons Learned from Natural Gas STAR Partners, 

2006.

112 U.S. EPA Natural Gas STAR, Compressor Best Practices, Methane 

to Markets, 2006.

113 PEMEX is Mexico’s national petroleum company.

114 U.S. EPA Natural Gas STAR, Reducing Emissions, Increasing 

Efficiency, Maximizing Profits, Methane to Markets, Natural Gas 

STAR International, 2008. Available at www.epa.gov/gasstar/

international/index.html.

115 Targa Resources and the Gas Processors Association, Methane 

Savings from Compressors and VRUs, Innovative Technologies 

for the Oil & Gas Industry: Product Capture, Process 

Optimization, and Pollution Prevention, July 27, 2006.

116 U.S. EPA Natural Gas STAR, Reducing Emissions, Increasing 

Efficiency, Maximizing Profits, Methane to Markets, Natural Gas 

STAR International, 2008. Available at www.epa.gov/gasstar/

international/index.html.

117 Ibid. 

118 Gas Research Institute Canada, Handbook for Estimating 

Methane Emissions from Canadian Natural Gas Systems, 1998.

119 U.S. EPA Natural Gas STAR, Reduced Methane Emissions from 

Compressor Rod Packing Systems, Lessons Learned from 

Natural Gas STAR Partners, October 2006.

120 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

121 Lev-On, M., Best Management Practices for Methane Emission 

Reductions, Natural Gas Star International, March 2010.

122 U.S. EPA Natural Gas STAR, Reducing Emissions, Increasing 

Efficiency, Maximizing Profits, Methane to Markets, Natural Gas 

STAR International, 2008. Available at www.epa.gov/gasstar/

international/index.html.

123 U.S. EPA Natural Gas STAR, Reduced Methane Emissions from 

Compressor Rod Packing Systems, Lessons Learned from 

Natural Gas STAR Partners, October 2006.

124 U.S. EPA, Cost-Effective Methane Emissions Reductions for 

Small and Midsize Natural Gas Producers, Journal of Petroleum 

Technology, June 2005.

125 Colorado Oil and Gas Conservation Commission Rule 805(b)(2)

(E).

126 Wyoming Oil and Gas Production Facilities, Chapter 6, Section 

2 Permitting Guidance, March 2010; “WY Revised March 2010 

Guidance.”

127 U.S. EPA Natural Gas STAR, Options for Reducing Methane 

Emissions from Pneumatic Devices in the Natural Gas Industry, 

Lessons Learned from Natural Gas STAR Partners, October 2006.

128 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

129 U.S. EPA and Occidental Oil & Gas Corporation, Methane 

Recovery from Pneumatic Devices, Vapor Recovery Units and 

Dehydrators, Methane to Markets, October 6, 2005.

130 U.S. EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005.

131 U.S. EPA Natural Gas STAR, Options for Reducing Methane 

Emissions from Pneumatic Devices in the Natural Gas Industry, 

Lessons Learned from Natural Gas STAR Partners, October 2006. 

132 U.S. EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005.

133 U.S. EPA and Occidental Oil & Gas Corporation, Methane 

Recovery from Pneumatic Devices, Vapor Recovery Units and 

Dehydrators, Methane to Markets, October 6, 2005.

134 U.S. EPA Natural Gas STAR, Options for Reducing Methane 

Emissions from Pneumatic Devices in the Natural Gas Industry, 

Lessons Learned from Natural Gas STAR Partners, October 2006. 

135 U.S. EPA, Cost-Effective Methane Emissions Reductions for 

Small and Midsize Natural Gas Producers, Journal of Petroleum 

Technology, June 2005.

136 U.S. EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005.

137 U.S. EPA Natural Gas STAR, Convert Gas Pneumatic Controls 

to Instrument Air, Lessons Learned from Natural Gas STAR 

Partners, 2006.

138 Smith, G.R., BP America Production Company, Natural Gas 

Industry Green House Gas Control & Business Opportunity 

Presentation, 2007.
PAGE 63 | Leaking Profits

139 Star-Tribune Energy Reporter, October 11, 2010.

140 U.S. EPA and Occidental Oil & Gas Corporation, Methane 

Recovery from Pneumatic Devices, Vapor Recovery Units and 

Dehydrators, Methane to Markets, October 6, 2005.

141 American Petroleum Institute, Procedures for Welding or Hot 

Tapping on Equipment in Service, API Recommended Practice 

2201, Third Edition and Fourth Edition, October 1985 and 

September 1995.

142 U.S. EPA Natural Gas STAR, Using Pipeline Pump-down 

Techniques to Lower Gas Line Pressure Before Maintenance, 

Lessons Learned from Natural Gas STAR Partners, 2009.

143 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

144 PEMEX and U.S. EPA Natural Gas STAR, Pipeline Maintenance 

and Repair, Methane to Markets, Technology Transfer Workshop, 

Villahermosa, Mexico, April, 2006.

145 U.S. EPA Natural Gas STAR, Using Hot Taps for in Service 

Pipeline Connections, Lessons Learned from Natural Gas STAR 

Partners, 2009.

146 U.S. EPA Natural Gas STAR, Inject Blowdown Gas into Low 

Pressure Mains, PRO Fact Sheet No. 401, 2004.

147 U.S. EPA Natural Gas STAR, Using Pipeline Pump-down 

Techniques to Lower Gas Line Pressure Before Maintenance, 

Lessons Learned from Natural Gas STAR Partners, 2009.

148 U.S. EPA, Cost-Effective Methane Emissions Reductions for 

Small and Midsize Natural Gas Producers, Journal of Petroleum 

Technology, June 2005.

149 Goodyear, M.A. (Comm Engineering), Graham, A.L. 

(TotalFinaElf E&P, Inc.) et al., Vapor Recovery of Natural Gas 

Using Non-Mechanical Technology, Society of Petroleum 

Engineers, Paper No. 800599, 2003. 

150 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

151 The U.S. EPA’s proposed NSPS requirements would apply to 

vessels with a throughput equal to or greater than 1 barrel of 

condensate per day or 20 barrels of crude oil per day, which are 

equivalent to VOC emissions of about 6 tons per year.

152 U.S. EPA Natural Gas STAR Partners, Reducing Methane 

Emissions with Vapor Recovery on Storage Tanks, Methane 

to Markets, Oil & Gas Subcommittee Technology Transfer 

Workshop, January 28, 2009.

153 U.S. EPA Natural Gas STAR, Reducing Methane Emissions 

with Vapor Recovery on Storage Tanks, Lessons learned from 

the Natural Gas STAR Partners, March 23, 2010, Newfield 

Exploration Company, Anadarko Petroleum Corporation, Utah 

Petroleum Association, Interstate O&G Compact Commission, 

Independent Petroleum Association of Mountain States.

154 Ibid.

155 Ibid.

156 Richards, L.S., Hy-Bon Engineering, Co., Fundamentals of Vapor 

Recovery, Associated Gas is Lost Product and Lost Revenue, 

October 2005.

157 Boyer, B.E.(COMM Engineering), and O’Connell, S.C. (Devon 

Energy Corp.), Optimize Separator Operating Pressures to 

Reduce Flash Losses, Society of Petroleum Engineers (SPE) 

Paper No. 94373-MS, 2005.

158 Avoiding oxygen entrainment in any gas piping and distribution 

system is a typical engineering design requirement, and is not 

unique to vapor recovery units design.

159 U.S. EPA, Methane’s Role in Promoting Sustainable 

Development in the Oil and Natural Gas Industry, 2009. 

160 Squarek, J. (Canadian Association of Petroleum Producers), 

Layer, M. (Environment Canada) and Picard, D. (Clearstone 

Engineering Ltd.), Development of a Best Management Practice 

in Canada for Controlling Fugitive Emissions at Upstream Oil 

and Gas Facilities, 2005.

161 Heath, M.W., Leak Detection and Quantification of Fugitive 

Methane Emissions at Natural Gas Facilities, 2009.

162 TransCanada, Methane Savings from Natural Gas Compressors, 

Energy Management Workshop, January 16, 2007. 

163 Picard, D. (Clearstone Engineering Ltd.), Cost Effective 

Opportunities to Reduce Methane Emissions and Losses, 2005.

164 U.S. EPA Natural Gas Star, Reducing Methane Emissions 

through Directed Inspection and Maintenance (DI&M), 

Methane to Markets, Oil & Gas Subcommittee Technology 

Transfer Workshop, 2009.

165 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

166 Code of Federal Regulations, Title 40: Protection of Environment 

(40 CFR) 60, Standards of Performance for New Stationary 

Sources, subpart VVa.

167 U.S. EPA, Oil and Gas Sector: New Source Performance 

Standards and National Emission Standards for Hazardous Air 

Pollutants Reviews, August 23, 2011, Federal Register, v. 76, No. 

163 (76 FR 52738), EPA Docket No. EPA–HQ–OAR–2010–0505, 

FRL–9448–6. Available at http://www.epa.gov/airquality/

oilandgas/index.html.

168 U.S. EPA Natural Gas Star, Reducing Methane Emissions 

through Directed Inspection and Maintenance (DI&M), 

Methane to Markets, Oil & Gas Subcommittee Technology 

Transfer Workshop, 2009.

169 .S. EPA Natural Gas STAR, Directed Inspection and Maintenance 

at Gas Processing Plants and Booster Stations, Lessons Learned 

from Natural Gas STAR Partners, 2003.

170 U.S. EPA Natural Gas STAR, Directed Inspection and 

Maintenance at Compressor Stations, Lessons Learned from 

Natural Gas STAR Partners, 2003.

171 U.S. EPA Natural Gas STAR, Reducing Methane Emissions 

Through Directed Inspection and Maintenance (DI&M), 

Methane to Markets, Oil & Gas Subcommittee Technology 

Transfer Workshop, 2009.

172 NRDC and other environmental organizations, Comments on 

New Source Performance Standards and National Emission 

Standards for Hazardous Air Pollutants Reviews, Proposed Rule, 

November 30, 2011, EPA Docket No. EPA-HQ-OAR-2010-0505, 

Document ID No. EPA-HQ-OAR-2010-0505-4240. Available at 

www.regulations.gov.

173 U.S. EPA Natural Gas STAR, Reduced Emissions Completions 

for Hydraulically Fractured Natural Gas Wells, Lessons Learned 

from Natural Gas STAR Partners, 2011.

174 U.S. EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005. 

175 U.S. EPA, ExxonMobil Production Company, and American 

Petroleum Institute, Green Completions, Lessons Learned from 

Natural Gas STAR, Producers Technology Transfer Workshop, 

September 21, 2004.
PAGE 64 | Leaking Profits

176 O’Connell, S., Devon Energy, EPA Natural Gas STAR Program 

Presentation, March 2007.

177 U.S. EPA and Devon Energy, Reduced Emissions Completions 

(Green Completions), Natural Gas STAR Producers Technology 

Transfer Workshop, Casper, Wyoming, August 30, 2005.

178 Ibid.

179 Smith, G.R., BP America Production Company, Natural Gas 

Industry Green House Gas Control & Business Opportunity 

Presentation, 2007.

180 The Williams Companies, Reducing Methane Emissions During 

Completion Operations – Economics Volume Recovered, 

Williams Production RMT Piceance Basin Operations, Natural 

Gas Star Producers Technology Transfer Workshop, September 

11, 2007.

181 U.S. EPA and ICF International, Methane’s Role in Promoting 

Sustainable Development in the Oil and Natural Gas Industry, 

2009.

182 U.S. EPA Natural Gas STAR Partners, Reduced Emission 

Completions/Plunger Lift and Smart Automation, Methane 

to Markets, Oil & Gas Subcommittee Technology Transfer 

Workshop, Monterrey, Mexico, January, 2009.

183 ICF Incorporated, Technical Assistance for the Draft 

Supplemental Generic EIS: Oil, Gas and Solution Mining 

Regulatory Program, prepared for New York State, August 5, 

2009.

184 U.S. EPA, Oil and Natural Gas Sector: Standards of Performance 

for Crude Oil and Natural Gas Production, Transmission and 

Distribution, Background Technical Support for Proposed 

Standards (NSPS TSD), 2011, pages 4-15 to4-18. Available at 

http://www.epa.gov/airquality/oilandgas/index.html.

185 U.S. EPA Natural Gas STAR, Installing Plunger Lift Systems in 

Gas Wells, Lessons Learned from Natural Gas STAR Partners, 

2006.

186 Ibid.

187 U.S. EPA Natural Gas Star, Reduced Emission Completions/

Plunger Lift and Smart Automation, Methane to Markets, Oil & 

Gas Subcommittee Technology Transfer Workshop, Monterrey, 

Mexico, January 2009.

188 U.S. EPA Natural Gas STAR, Installing Plunger Lift Systems in 

Gas Wells, Lessons Learned from Natural Gas STAR Partners, 

2006.

189 U.S. EPA Natural Gas STAR, Optimize Glycol Circulation and 

Install Flash Tank Separators in Glycol Dehydrators, Lessons 

Learned from Natural Gas STAR Partners, 2009.

190 U.S. EPA Natural Gas STAR, Natural Gas Dehydration, Natural 

Gas STAR Producers Technology Transfer Workshop, Durango, 

Colorado, September 13, 2007.

191 EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005.

192 U.S. EPA Natural Gas STAR, Natural Gas Dehydration, Natural 

Gas STAR Producers Technology Transfer Workshop, Durango, 

Colorado, September 13, 2007.

193 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011.

194 U.S. EPA Natural Gas STAR, Replacing Glycol Dehydrators with 

Desiccant Dehydrators, Lessons Learned from Natural Gas STAR 

Partners, 2009. 

195 Smith, G.R., BP America Production Company, Natural Gas 

Industry Green House Gas Control & Business Opportunity 

Presentation, 2007.

196 U.S. EPA Natural Gas STAR, Replacing Wet Seals with Dry Seals 

in Centrifugal Compressors, Lessons Learned from Natural Gas 

STAR Partners, 2006.

197 U.S. EPA Natural Gas STAR, Replacing Wet Seals with Dry Seals 

in Centrifugal Compressors, 2009, EPA 430-B-03-012.

198 U.S. EPA, Inventory of U.S. Greenhouse Gas Emissions and 

Sinks (1990-2009), April 15, 2011. 

199 U.S. EPA, Methane to Markets, Reducing Emissions, Increasing 

Efficiency, Maximizing Profits, 2008. Available at www.epa.gov/

gasstar/international/index.html.

200 Targa Resources and the Gas Processors Association, Methane 

Savings from Compressors and VRUs, Innovative Technologies 

for the Oil & Gas Industry: Product Capture, Process 

Optimization, and Pollution Prevention, July 27, 2006.

201 U.S. EPA, Oil and Natural Gas Sector: Standards of Performance 

for Crude Oil and Natural Gas Production, Transmission and 

Distribution, Background Technical Support for Proposed 

Standards (NSPS TSD), 2011, pages 6-19 to 6-22. Available at 

http://www.epa.gov/airquality/oilandgas/index.html.

202 U.S. EPA Natural Gas STAR, Reduced Methane Emissions from 

Compressor Rod Packing Systems, Lessons Learned from 

Natural Gas STAR Partners, October 2006.

203 U.S. EPA, Cost-Effective Methane Emissions Reductions for 

Small and Midsize Natural Gas Producers, Journal of Petroleum 

Technology, June 2005.

204 U.S. EPA, Oil and Natural Gas Sector: Standards of Performance 

for Crude Oil and Natural Gas Production, Transmission and 

Distribution, Background Technical Support for Proposed 

Standards (NSPS TSD), 2011, pages 6-15 – 6-18. Available at 

http://www.epa.gov/airquality/oilandgas/index.html.

205 U.S. EPA and Occidental Oil & Gas Corporation, Methane 

Recovery from Pneumatic Devices, Vapor Recovery Units and 

Dehydrators, Methane to Markets, October 6, 2005.

206 U.S. EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005.

207 U.S. EPA, Cost-Effective Methane Emissions Reductions for 

Small and Midsize Natural Gas Producers, Journal of Petroleum 

Technology, June 2005.

208 U.S. EPA Natural Gas STAR, Options for Reducing Methane 

Emissions from Pneumatic Devices in the Natural Gas Industry, 

Lessons Learned from Natural Gas STAR Partners, October 2006.

209 Smith, G.R., BP America Production Company, Natural Gas 

Industry Green House Gas Control & Business Opportunity 

Presentation, 2007.

210 U.S. EPA, Oil and Natural Gas Sector: Standards of Performance 

for Crude Oil and Natural Gas Production, Transmission and 

Distribution, Background Technical Support for Proposed 

Standards (NSPS TSD), 2011, pages 5-14 to 5-17. Available at 

http://www.epa.gov/airquality/oilandgas/index.html.

211 U.S. EPA Natural Gas STAR, Cost-Effective Methane Emission 

Reductions for Small and Mid-Size Natural Gas Producers, 

Corpus Christi, Texas, November 1, 2005.

212 U.S. EPA, Cost-Effective Methane Emissions Reductions for 

Small and Midsize Natural Gas Producers, Journal of Petroleum 

Technology, June 2005.
PAGE 65 | Leaking Profits

213 U.S. EPA Natural Gas STAR, Convert Gas Pneumatic Controls 

to Instrument Air, Lessons Learned from Natural Gas STAR 

Partners, 2006.

214 U.S. EPA, Oil and Natural Gas Sector: Standards of Performance 

for Crude Oil and Natural Gas Production, Transmission and 

Distribution, Background Technical Support for Proposed 

Standards (NSPS TSD), 2011, pages 5-19 to 5-22. Available at 

http://www.epa.gov/airquality/oilandgas/index.html.

215 U.S. EPA Natural Gas STAR, Reducing Methane Emissions 

with Vapor Recovery on Storage Tanks, Lessons learned from 

the Natural Gas STAR Partners, March 23, 2010, Newfield 

Exploration Company, Anadarko Petroleum Corporation, Utah 

Petroleum Association, Interstate O&G Compact Commission, 

Independent Petroleum Association of Mountain States.

216 Ibid.

217 Ibid.

218 Richards, L.S., Hy-Bon Engineering, Co., Fundamentals of Vapor 

Recovery, Associated Gas is Lost Product and Lost Revenue, 

October 2005.

219 U.S. EPA, Oil and Natural Gas Sector: Standards of Performance 

for Crude Oil and Natural Gas Production, Transmission and 

Distribution, Background Technical Support for Proposed 

Standards (NSPS TSD), 2011, pages 7-13 to 7-14. Available at 

http://www.epa.gov/airquality/oilandgas/index.html.

220 U.S. EPA Natural Gas STAR, Directed Inspection and 

Maintenance at Gas Processing Plants and Booster Stations, 

Lessons Learned from Natural Gas STAR Partners, 2003.

221 U.S. EPA Natural Gas STAR, Directed Inspection and 

Maintenance at Compressor Stations, Lessons Learned from 

Natural Gas STAR Partners, 2003.

222 U.S. EPA Natural Gas Star, Reducing Methane Emissions 

through Directed Inspection and Maintenance (DI&M), 

Methane to Markets, Oil & Gas Subcommittee Technology 

Transfer Workshop, 2009. 

223 TransCanada, Methane Savings from Natural Gas Compressors, 

Energy Management Workshop, January 16, 2007.

224 U.S. EPA, Oil and Natural Gas Sector: Standards of Performance 

for Crude Oil and Natural Gas Production, Transmission and 

Distribution, Background Technical Support for Proposed 

Standards (NSPS TSD), 2011, pages 8-23 to 8-30, mainly Tables 

8-14 to 8-17. Available at http://www.epa.gov/airquality/

oilandgas/index.html.
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