Economic Analysis of

Methane Emission

Reduction Opportunities

in the U.S. Onshore Oil

and Natural Gas

Industries

   

March 2014

Prepared for

Environmental Defense Fund

257 Park Avenue South

New York, NY 10010

Prepared by

ICF International

9300 Lee Highway

Fairfax, VA 22031
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page
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

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ICF International iii March 2014

Contents

1. Executive Summary .................................................................................................................... 1‐1

2. Introduction ............................................................................................................................... 2‐1

2.1. Goals and Approach of the Study ..............................................................................................2‐1

2.2. Overview of Gas Sector Methane Emissions.............................................................................2‐2

2.3. Climate Change‐Forcing Effects of Methane.............................................................................2‐5

2.4. Cost‐Effectiveness of Emission Reductions...............................................................................2‐6

3. Approach and Methodology ....................................................................................................... 3‐1

3.1. Overview of Methodology.........................................................................................................3‐1

3.2. Development of the 2011 Emissions Baseline...........................................................................3‐2

3.3. Projection to 2018 .....................................................................................................................3‐4

3.4. Identification of Targeted Emission Sources.............................................................................3‐6

3.5. Selected Mitigation Technologies .............................................................................................3‐9

3.6. Source Categories Not Addressed ...........................................................................................3‐23

4. Analytical Results ....................................................................................................................... 4‐1

4.1. Development of Emission Control Cost Curves.........................................................................4‐1

4.2. Emission Reduction Cost Curves................................................................................................4‐2

4.3. Co‐Benefits ..............................................................................................................................4‐11

5. Case Studies ............................................................................................................................... 5‐1

5.1. Wet Seal Compressor Degassing for Centrifugal Compressors.................................................5‐1

5.2. Dry Seal Replacement/Retrofit..................................................................................................5‐2

5.3. Wet Seal Degassing Capture Systems........................................................................................5‐2

5.3.1. Economic Analysis of Installing Wet Seal Degassing Capture Systems........................5‐3

5.4. Liquids Unloading ......................................................................................................................5‐6

5.4.1. Background...................................................................................................................5‐6

5.4.2. Plunger Lifts..................................................................................................................5‐7

5.4.3. Additional Options for Removing or Remediating Liquids Problems...........................5‐9

5.4.4. Liquids Issues in Horizontal Wells...............................................................................5‐12

6. Conclusions ................................................................................................................................ 6‐1

Appendix A. Additional Sensitivities..................................................................................................A‐1

Appendix B. Development of the 2011 Emissions Baseline................................................................B‐1

Appendix C. Emission Projection to 2018 .......................................................................................... C‐1

Appendix D. Methane Mitigation Technologies.................................................................................D‐1

Figures

Figure 1‐1 ‐ Marginal Abatement Cost Curve for Methane Reductions by Source ...................................1‐2

Figure 2‐1 ‐ Natural Gas Industry Processes and Example Methane Emission Sources............................2‐3

Figure 3‐1 – Emission Projection to 2018 – (Including Offshore) ..............................................................3‐5

Figure 3‐2 ‐ Distribution of Emissions in 2018 ........................................................................................... 3‐5
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

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Figure 3‐3 ‐ EIA Oil and Gas Regions.......................................................................................................... 3‐6

Figure 3‐4 ‐ 2018 Projected Onshore Emissions........................................................................................ 3‐8

Figure 3‐5 ‐ Reciprocating Compressor Rod Packing ............................................................................... 3‐13

Figure 3‐6 ‐ Wet Seal Compressor Schematic.......................................................................................... 3‐15

Figure 3‐7 ‐ Plunger Lift Schematic .......................................................................................................... 3‐17

Figure 4‐1 ‐ Example MAC Curve ............................................................................................................... 4‐2

Figure 4‐2 – National Aggregate MAC Curve for Baseline Technology Assumptions................................4‐3

Figure 4‐3 ‐ Distribution of Emission Reduction Potential......................................................................... 4‐5

Figure 4‐4 ‐ Emission Reduction by Industry Segment .............................................................................. 4‐6

Figure 4‐5 – Emission Reductions for the Gas Production Segment .........................................................4‐7

Figure 4‐6 ‐ Emission Reductions for the Oil Production Segment............................................................4‐8

Figure 4‐7 ‐ Emission Reductions for the Gathering and Boosting Segment.............................................4‐9

Figure 4‐8 ‐ Emissions Reductions for the Gas Transmission Segment .....................................................4‐9

Figure 4‐9 ‐ National Aggregate MAC Curve with Baseline Technology Assumption and

Economy‐Wide Value Recognition......................................................................................... 4‐10

Figure 4‐10 ‐ National Aggregate MAC Curve by Region .........................................................................4‐11

Figure 4‐11 – Co‐Benefit Reductions of VOCs and HAPs.........................................................................4‐12

Figure 4‐12 ‐ VOC Reduction Co‐Benefits................................................................................................ 4‐12

Figure 4‐13 ‐ Hazardous Air Pollutant Co‐Benefits .................................................................................. 4‐13

Figure 5‐1 ‐ Dry Seals on a Centrifugal Compressor .................................................................................. 5‐2

Figure 5‐2 Wet seal degassing recovery system for centrifugal compressors (Source U.S.

EPA) ..........................................................................................................................................5‐3

Figure 5‐3 ‐ Plunger Lift Schematic ............................................................................................................ 5‐7

Figure 5‐4 ‐ Installation of Velocity Tubing Serving to Reduction the Cross Section Area of

the Production Tubing............................................................................................................ 5‐11

Figure 5‐5 ‐ Different Types of Horizontal Wells...................................................................................... 5‐13

Tables

Table 3‐1 ‐ Summary of 2011 Methane Emissions Baseline...................................................................... 3‐3

Table 3‐2 ‐ Highest Emitting Onshore Methane Source Categories in 2018 .............................................3‐7

Table 3‐3 ‐ LDAR Hourly Cost Calculation ................................................................................................ 3‐10

Table 3‐4 – Cost Calculation – Quarterly LDAR........................................................................................ 3‐12

Table 3‐5 ‐ Assumptions for Rod Packing Replacement ..........................................................................3‐14

Table 3‐6 ‐ Summary of Mitigation Measures Applied............................................................................ 3‐21

Table 3‐7 ‐ Summary of Mitigation Measure Characteristics..................................................................3‐22

Table 4‐1 – Annualized Cost and Reduction and Initial Capital Cost .........................................................4‐4

Table 4‐2 ‐ Initial Capital Cost by Industry Segment.................................................................................. 4‐7

Table 5‐1 ‐ Degassing Recovery System Estimated Installation and Equipment Costs .............................5‐4

Table 5‐2 ‐ Wet Seal Degassing Recovery System Costs and Savings for One Compressor ......................5‐6

Table 5‐3 ‐ Wet Seal Degassing Recovery System Costs and Savings for Four Compressors

at a Station ............................................................................................................................... 5‐6

Table 5‐4 ‐ Reported Capital and Operating Cost Ranges for Installing Plunger Lift

Systems ....................................................................................................................................5‐9
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ICF International v March 2014

Acknowledgement

ICF received and considered data and commentary from numerous stakeholder organizations,

including oil and gas producers, pipelines, equipment vendors, service providers, and a trade

organization.  No information in this report should be attributed to any single organization, as all

data is aggregated from multiple sources and often uses average values.  Furthermore,

acknowledgement of industry participation does not imply their agreement with the study

conclusions, which reflect the professional judgment of ICF.

We thank all of the stakeholder organizations for providing input to this study, and specifically

acknowledge the following entities: Anadarko Petroleum, BG Group, Pioneer Natural Resources,

Southwestern Energy, and the American Gas Association.

   
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Acronyms and Abbreviations

Acronym / Abbreviation Stands For

AEO Annual Energy Outlook

BAMM Best Available Monitoring Methods

bbl Barrel

Bcf Billion Cubic Feet

BTEX Benzene, Toluene, Ethylbenzene, and Xylenes

CapEx Capital Expenditures

CH4 Methane

CO2 Carbon Dioxide

CO2e Carbon Dioxide Equivalent

DI&M Directed Inspection and Maintenance

EDF Environmental Defense Fund

EIA U.S. Energy Information Administration

EPA U.S. Environmental Protection Agency

ESD Emergency Shutdown

FERC Federal Energy Regulatory Commission

GDP Gross Domestic Product

GGFR Global Gas Flaring Reduction

GHG Greenhouse Gas

GHGRP Greenhouse Gas Reporting Program

HAP Hazardous Air Pollutant

hp Horsepower

IR Infrared

LDAR Leak Detection and Repair

LDCs Local Distribution Companies

LNG Liquefied Natural Gas

MAC Marginal Abatement Cost

Mcf Thousand Cubic Feet

MMcf Million Cubic Feet

MMTCH4 Million Metric Tonnes Methane
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Acronym / Abbreviation Stands For

MMTCO2e Million Metric Tonnes CO2 equivalent

NESHAP National Emission Standards for Hazardous Air Pollutants

NPV Net Present Value

NSPS New Source Performance Standards promulgated under the Federal Clean Air Act

OpEx Operating Expenditures

PRO Partner Reported Opportunity

psig Pounds per Square Inch – Gauge

RECs Reduced Emission Completions

scf Standard Cubic Feet

scfd Standard Cubic Feet per Day

scfh Standard Cubic Feet per Hour

scfm Standard Cubic Feet per Minute

TEG Triethylene Glycol

TSD Technical Support Document

USD U.S. Dollars

VOC Volatile Organic Compound

VRU Vapor Recovery Unit
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

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Executive Summary

ICF International 1‐1 March 2014  

1. Executive Summary

Methane is an important climate change forcing greenhouse gas (GHG) with a short‐term impact many

times greater than carbon dioxide.  Methane comprised 9% of U.S. greenhouse gas (GHG) emissions in

2011 according to the U.S. EPA Inventory of US Greenhouse Gas Emission and Sinks: 1990‐20111

, and

would comprise a substantially higher portion based on a shorter timescale measurement. Recent

research also suggests that mitigation of short‐term climate forcers such as methane is a critical

component of a comprehensive response to climate change2

. Emissions from the oil and gas industry are

among the largest anthropogenic sources of U.S. methane emissions. At the same time, there are many

ways to reduce emissions of fugitive and vented methane from the oil and gas industry and, because of

the value of the gas that is conserved, some of these measures actually save money or have limited net

cost.  

Environmental Defense Fund (EDF) commissioned this economic analysis of methane emission reduction

opportunities from the oil and natural gas industries to identify the most cost‐effective approaches to

reduce these methane emissions. The study projects the estimated growth of methane emissions from

these industries through 2018 as a future date at which new emission reduction technologies could be

installed. It then identifies the largest emitting segments and estimates the magnitude and cost of

potential reductions achievable through currently available technologies. The key conclusions of the

study include:

 Emission Growth ‐ Methane emissions from oil and gas activities are projected to grow 4.5% from

2011 to 2018 including reductions from EPA regulations adopted in 2012 (known as New Source

Performance Standards (NSPS) Subpart  OOOO). All of the projected net growth is from the oil

sector, largely from flaring and venting of associated gas. Growth from new natural gas sources is

offset by the NSPS and other continuing emission reduction activities. Nearly 90% of the emissions

in 2018 come from existing sources (sources in existence in 2011).

 80/20 Rule for Sources ‐ 22 of the over 100 emission source categories account for over 80% of the

2018 emissions, primarily at existing facilities.

 Abatement Magnitude and Economics ‐ A 40% percent reduction in onshore methane emissions is

projected to be achievable with existing technologies and techniques at a net total cost of

$0.66/Mcf of methane reduced, or less than $0.01/Mcf of gas produced, taking into account savings

that accrue directly to companies implementing methane reduction measures (Figure 1‐1). If the full

economic value of recovered natural gas is taken into account, including savings that do not directly

accrue to companies implementing methane reduction measures, the 40% reduction is achievable

                                                            

1 Calculated at a 100 year GWP of 21 – see Section 2.3. 2 Shoemaker, J. et. al., “What Role for Short‐Lived Climate Pollutants in Mitigation Policy?”. Science Vol 342 13 December 2013
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Executive Summary

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while saving the U.S. economy and consumers over $100 million per year.  The cost for some

measures and segments of the industry is more or less than the net total. The initial capital cost of

the measures is estimated to be approximately $2.2 billion with the majority of the costs in the oil

and gas production segments.

Figure 1‐1 ‐ Marginal Abatement Cost Curve for Methane Reductions by Source

 Abatement Opportunities – By volume, the largest opportunities target leak detection and repair of

fugitive emissions (“leaks”) at facilities and gas compressors, reduced venting of associated gas, and

replacement of high‐emitting pneumatic devices.

 Co‐Benefits – Reducing methane emissions will also reduce ‐ at no extra cost ‐ conventional

pollutants that can harm public health and the environment. The methane reductions projected

here would also result in a 44% reduction in volatile organic compounds (VOCs) and hazardous air

pollutants (HAPs) associated with methane emissions from the oil and gas industry.  

There are several caveats to the results:

 The 2011 EPA inventory is the best starting point for analysis, but it is based on many assumptions

and some older data sources. Although the inventory is improving with new data, it is designed to

be a planning and reporting document and is imperfect, especially at the detailed level, for a

granular analysis of this type.

 Emission mitigation cost and performance are highly site specific and variable. The values used here

are estimated average values.
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Executive Summary

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 The analysis presents a reasonable estimate of potential cost and magnitude of reductions within a

range of uncertainty.
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Introduction

ICF International 2‐1 March 2014  

2. Introduction

Methane emissions have an enhanced effect on climate change because methane has a climate forcing

effect 25 times greater on a 100 year basis than that of carbon dioxide, the primary greenhouse gas

(GHG). Methane’s impact is almost three times greater on a 20 year basis and there is research that may

cause both factors to be increased. (See Section 2.3)  Recent research also suggests that mitigation of

short‐term climate forcers such as methane is a critical component of a comprehensive response to

climate change.

Emissions from the oil and gas industries are among the largest anthropogenic sources of U.S. methane

emissions according to the U.S. EPA Inventory of U.S. Greenhouse Gas Emissions 3

, and recent analyses

indicate that the EPA inventory estimates may understate total methane emissions from this source

category4

. At the same time, there are many ways to reduce emissions of fugitive and vented methane

from the oil and gas industries and, because of the value of the gas that is conserved, some of these

measures actually save money or have limited net cost.  

Companies in the oil and gas industries have made significant voluntary reductions in methane

emissions. However, voluntary adoption of control techniques is uneven.  The U.S. has established

emission regulations for conventional pollutants (NSPS Subpart OOOO and oil and gas NESHAPS) that

will have the effect of significantly reducing methane emissions from certain new sources in some

segments of the gas industry. Some states also have proposed or established regulations that limit

methane emissions from the oil and gas industry. However, these regulations generally do not apply to

emissions from the existing infrastructure, so there is a large population of uncontrolled sources.

Overall, methane emissions are significant and there is a sizeable potential for additional cost‐effective

reduction opportunities.

2.1. Goals and Approach of the Study

Environmental Defense Fund (EDF) commissioned this economic analysis of methane emission reduction

opportunities from the oil and natural gas industry. This ICF analysis is solutions‐oriented and

complements EDF’s ongoing work on methane emissions in the oil and natural gas sectors. The

approach to the study was to:

 Define a baseline of methane emissions from the oil and gas sectors. The baseline was established

for 2018 as a conservative estimate of a point when new mitigation technologies could have been

installed.

                                                            

3 U.S. EPA, “Inventory of U.S. Greenhouse Gas Emissions And Sinks: 1990‐2011”. April 2013.

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html Based on a 100 year GWP of 21 – see Section 2.3 4 Brandt, A. et. al., “Methane Leaks from North American Natural Gas Systems”. Science VOL 343 14 February 2014
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Introduction

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 Review existing literature and conduct further analysis to identify the largest reduction

opportunities and validate and refine cost‐benefit estimates of mitigation technologies.

 Conduct interviews with industry, technology innovators, and equipment vendors with a specific

focus to identify additional mitigation options.

 Use this information to develop marginal abatement cost (MAC) curves for methane reductions in

these industries.

 Document and present the results.

The final outputs of the study include:

 The projected 2018 emissions baseline. (Chapter 3 and Appendix C)

 Inventory of methane mitigation technologies. (Chapters 3 and 6 and Appendix D)

 Emissions abatement cost curves across a range of scenarios (Chapter 4 and Appendix A)

 In‐depth case studies of two specific methane mitigation options. (Chapter 5)

 Conclusions (Chapter 6)

2.2. Overview of Gas Sector Methane Emissions

There are many sources of methane emissions across the entire oil and gas supply chain. These

emissions are characterized as either:

 Fugitive emissions – methane that “leaks” unintentionally from equipment such as from flanges,

valves, or other equipment.

 Vented emissions – methane that is released due to equipment design or operational procedures,

such as from pneumatic device bleeds, blowdowns, incomplete combustion, or equipment venting.

Although ‘leaks’ is sometimes used to refer to all methane emissions from the oil and gas industry, we

use the more narrow technical definitions in this report.

Figure 2‐1 illustrates the major segments of the natural gas industry and examples of the primary

sources of methane emissions as gas is produced, processed, and delivered to consumers. Natural gas is

produced along with oil in most oil wells (as “associated gas”) and also in gas wells that do not produce

oil (as “non‐associated gas”). Up until the past few years, most of the U.S. natural gas supply came from

the Gulf of Mexico and from western and southwestern states. More recently, mid‐continental and

northeastern shale plays have been a growing source of oil and gas supply.
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Figure 2‐1 ‐ Natural Gas Industry Processes and Example Methane Emission Sources

Sources: American Gas Association; EPA Natural Gas STAR Program

Raw gas (including methane) is vented at various points during the production process. Gas can be

vented when the well is “completed” at the initial phase of production. Further, because gas wells are

often in remote locations without electricity, the gas pressure is used to control and power a variety of

control devices and on‐site equipment, such as pumps. These pneumatic devices typically release or

“bleed” small amounts of gas during their operation. In both oil and gas production, water and

hydrocarbon liquids are separated from the product stream at the wellhead.  The liquids release gas,

which may be vented from tanks unless it is captured. Water is removed from gas stream by glycol

dehydrators, which vent the removed moisture and some gas to the atmosphere. In some cases, the gas

released by these processes and equipment may be flared rather than vented, to maintain safety and to

relieve over‐pressuring within different parts of the gas extraction and delivery system. Flaring produces

CO2, a significant but less potent GHG than methane, but no flare is 100% efficient, and some methane is

emitted during flaring. In addition to the various sources of vented emissions, the many components

and complex network of small gathering lines have the potential for fugitive emissions.

Although some gas is pure enough to be used as‐is, most gas is first transported by pipeline from the

wellhead to a gas processing plant. The gathering system has pneumatic devices and compressors that

vent gas as well as potential fugitive emissions. Gas processing plants remove additional hydrocarbon

liquids such as ethane and butane as well as gaseous impurities from the raw gas, including CO2, in order

for the gas to be pipeline‐quality and ready to be compressed and transported. Such plants are another

source of fugitive and vented emissions.
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Introduction

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From the gas processing plant, natural gas is transported, generally over long distances by interstate

pipeline to the “city gate” hub and then to consumers. The vast majority of the compressors that

pressurize the pipeline to move the gas are fueled by natural gas, although a small share is powered by

electricity. Compressors emit CO2 and methane emissions during fuel combustion and are also a source

of fugitive and vented methane emissions through leaks in compressor seals, valves, and connections

and through venting that occurs during operations and maintenance.  Compressor stations constitute

the primary source of vented methane emissions in natural gas transmission.  

Some power plants and large industrial facilities receive gas directly from transmission pipelines, while

others as well as residential and commercial consumers have gas delivered through smaller distribution

pipelines operated by local gas distribution companies (LDCs). Distribution lines do not typically require

gas compression; however, some methane emissions do occur due to leakage from older distribution

lines and valves, connections, and metering equipment. This is especially true for older systems that

have cast iron distribution mains.

Many of the emission sources from domestic oil production are similar to those in gas production –

completion emissions, pneumatic devices, processing equipment and engine/compressors. Crude oil

contains natural gas and the gas is separated from the oil stream at the wellhead and can be captured

for sale, vented, or flared. Venting or flaring is most common in regions that do not have gas gathering

infrastructure. This is the case currently in North Dakota, where rapid growth in oil production has taken

place in a region with little gas gathering infrastructure. While new gathering lines are being built,

production is still ahead of the gathering capacity, resulting in continued flaring.  

Oil is taken from the wellhead in electric‐powered pipelines and more recently by rail, to refineries for

processing. Petroleum products are then taken to consumers by pipeline, truck, rail, or barge. The

downstream methane emissions in the petroleum sector are much smaller than in the gas sector as

most of the methane has been removed from the oil by this point.

For the last 100 years, domestic oil production has been primarily in the Southwest (Texas, Arkansas,

Oklahoma), the Gulf of Mexico, California, and Alaska.  Domestic gas production has been mostly in the

Southwest, Gulf of Mexico, and the Rockies.  More recently, the focus of new natural gas and oil

development has been in the extraction of gas from shale formations.  Shale is a sedimentary rock

composed of compacted mud, clay and organic matter.  Over time, the organic material can produce

natural gas and/or petroleum, which can slowly migrate into formations where it can be recovered from

conventional oil and gas wells. The shale rock itself is not sufficiently permeable to allow the gas to be

economically recovered through conventional wells; that is, gas will not flow sufficiently freely through

the shale to a well for production.

Gas and oil from shale formations is recovered by hydraulically fracturing the shale rock to release the

hydrocarbons.  This involves pumping water and additives at high pressure into the well to “fracture”

the shale, creating small cracks that allow the gas and/or oil to flow out.  When the water “flows back”
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

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Introduction

ICF International 2‐5 March 2014

out of the well, methane is entrained and may be vented.  Due to the high global warming potential of

methane, this can be a large source of GHGs.  For these reasons, the increased production of shale gas is

a potential source of increased GHG emissions.

Federal regulations promulgated in 2012 require the majority of new hydraulically fractured gas wells to

capture or flare the flow‐back gas. These regulations and other federal and state regulations also require

control of other methane‐emitting processes, though many apply only to new sources and to those

wells that primarily produce natural gas rather than wells that primarily produce oil, so there remains a

large population of existing uncontrolled sources.

Significant amounts of both oil and gas are produced from offshore facilities. While these facilities

report significant methane emissions, the reports do not have the detail and specificity of the rest of the

methane inventory and therefore cannot be included in the same methodology applied to the rest of

the inventory for this analysis. Therefore, this study focuses only on onshore oil and gas industry

operations. Additional study of offshore emissions and reduction opportunities would be a useful

follow‐up to this analysis.

2.3. Climate Change‐Forcing Effects of Methane

Different greenhouse gases persist in the atmosphere for different lengths of time and have different

warming effects, and thus have different effects on climate change.  In order to compare them, the

scientific community uses a factor called the global warming potential (GWP), which relates each GHG’s

effect to that of CO2, which is assigned a GWP of 1. The science and policy communities have historically

looked to the Intergovernmental Panel on Climate Change (IPCC) assessment reports as the

authoritative basis for GWP values. The currently accepted values are from the IPCC Fourth Assessment

report5 (AR‐4).

CO2 emissions determine the amount of climate change over the long term, due to their long lifetime in

the atmosphere.  Because stabilizing climate will require deep cuts in CO2 emissions, GWP values are

most commonly expressed on a 100‐year time horizon. On a 100‐year basis, methane is assigned a GWP

of 25 by the AR‐4. This means that one ton of methane has the same effect as 25 tons of CO2 over 100

years. The 100 year GWP is the standard value used by the EPA and other federal, state, and

international agencies to measure GHG emissions. (One exception is the EPA GHG inventory, which uses

a 100 GWP of 21, as specified by the United Nations Framework Convention on Climate Change (UNFCC)

inventory protocol.)

                                                            

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

the Intergovernmental Panel on Climate Change. (Cambridge University Press and New York, NY, Cambridge, United Kingdom,

2007).
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Introduction

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Some GHGs, including methane, have a stronger climate‐forcing effect than CO2 but a shorter lifetime in

the atmosphere (12 years for methane). In order to evaluate the short‐term effects, the GWP is also

calculated on a 20 year basis. On a 20 year basis, the AR‐4 assigns methane a GWP of 72. The IPCC is

currently preparing a Fifth Assessment Report (AR‐5)6

. The first phase of that work has adopted higher

GWP values due to updated data on methane’s role in the atmosphere. The AR‐5 values are a 100 year

GWP of 28 and a 20 year GWP of 84 for methane. In summary:

 The EPA GHG inventory uses a 100 year GWP of 21.

 Most other regulations and inventories (including the EPA Greenhouse Gas Reporting rule as of

2013) use the AR‐4 100 year GWP of 25. The AR‐4 20 year GWP is 72.

 The GWPs being put forth in the AR‐5 are 28 for 100 years and 84 for 20 years.

 This report uses the AR‐4 100 year GWP of 25 except where otherwise noted.

2.4. Cost‐Effectiveness of Emission Reductions

It is common in discussing emission reductions to describe “cost‐effective” emission reductions.

However, there are three different concepts of cost effectiveness that must be understood and

differentiated.

The first concept is cost‐effectiveness for the company implementing the measure. In this case, “cost‐

effective” means that the value of gas that is recovered through a methane reduction measure exceeds

the incremental capital and operating cost of the measure sufficiently to create a payback or rate‐of‐

return that meets the company’s investment criteria. Measures that meet these criteria might be

described as having a positive net present value (NPV), a short payback period, or an internal rate of

return that meets a certain threshold.

In order for a measure to meet this cost‐effectiveness criterion, the measure must recover the methane

emissions and be able to recover their monetary value. Flaring of methane emissions does not meet this

criterion, for example. In addition, the company must be able to monetize the value of the recovered

methane. For example, if a producer reduces methane losses, it will have more gas to sell and will

receive an economic benefit.  

The second concept is cost‐effectiveness at the economy‐wide scale. In segments in which the company

owns the gas, such as oil and gas production, the company can clearly monetize the value of reduced

gas losses. This is also true in some other sectors. Most midstream companies (gathering, processing,

                                                            

6 IPCC. “Climate Change 2013: The Physical Science Basis. Contribution of Working Group I to the Fifth Assessment Report of

the Intergovernmental Panel on Climate Change”. (Cambridge University Press and New York, NY, Cambridge, United Kingdom,

2013).
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

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storage) are paid a fixed fee for gas lost and consumed during their operations. If they can reduce their

losses then they will benefit directly from the reduced losses.  

Although transmission and local distribution companies typically have a similar cost structure, they are

usually required by regulators to return the value of reduced losses to their customers, so they cannot

recover the benefit of reduced methane losses. Methane reductions in these segments of the industry

will not have a positive return to the company or be “cost‐effective” in this sense. That said, the value of

reduced losses will accrue to other parts of the economy. If a pipeline or LDC reduces its losses, the

benefit will eventually flow through to the customers and to the economy overall. Reduced losses will

eventually flow through as lower prices for gas delivery and delivered cost of gas to consumers. Thus,

even when the entity implementing a reduction cannot directly benefit from reduced losses, there is a

broader benefit and that full economic benefit can be calculated and allocated against the cost of the

methane reduction, the second kind of cost‐effectiveness.

The last concept of cost‐effectiveness is in the context of pollution control programs. In conventional

pollution control programs the control technology rarely results in a cost reduction to the company that

is required to implement it. That is, the cost‐of‐control is almost always positive and the net present

value is negative and there is no payback for the investment. Nevertheless, these programs incorporate

the concept of cost‐effectiveness, meaning that the cost is acceptable to society as a means of meeting

public health and environmental goals. The cost‐effectiveness varies for different pollutants and

different regulatory programs. For example, $10,000/ton of VOC reduced may be considered cost‐

effective in some ozone non‐attainment areas while $100/ton of SO2 may be considered cost‐effective

for an acid rain reduction program. In this context, methane reductions can be considered cost‐effective

even if they have a net cost to the company or society overall. Where methane reductions do create a

net value to the implementing company, the cost‐of‐control will be negative, i.e., the company is

reducing emissions and saving money rather than spending money.

In this study, the value of recovered gas is included in calculating the cost‐effectiveness of mitigation

measures where the gas can be recovered and where it can be monetized by the company. Therefore,

the same measure may have different costs for different segments, e.g., reducing compressor emissions

will have a lower net cost in the production segment than in the transmission segment. This reflects the

net cost to the company to implement the measure. However, where gas can be recovered through a

mitigation measure, it will have value to the broader economy, even if it is not recognized by the

company that must make the investment. Therefore we also show, in certain cases, an economy‐wide

cost‐effectiveness measure, which recognizes the value of all recovered gas, even if it cannot be

recognized directly by the affected company. These cases are clearly labeled as such. The cost‐of‐

control, whether positive or negative, can be also evaluated in the regulatory sense and compared to

other available emission reduction options. Finally, there are additional social and environmental

benefits of methane reductions that are not captured in these calculations, including the broader
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

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ICF International 2‐8 March 2014

economic value of reduced climate risk and co‐benefit reductions of conventional pollutants such as

ground‐level ozone and hazardous air pollutants.
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3. Approach and Methodology

3.1. Overview of Methodology

This section provides an overview of the methodology applied for this study. The major steps were:

 Establish the 2011 Baseline for analysis – the analysis started with the most recent U.S. EPA

inventory of methane emissions in the EPA Inventory of U.S. GHG Emissions published in 2013 with

data for 20117

. This inventory was reviewed and revised to account for additional, more recent

information such as information from the EPA GHG Reporting Program8 and the University of

Texas/EDF gas production measurement study9

. These changes were applied to develop an ICF 2011

Baseline, which was used as the basis for projecting onshore methane emissions to 2018.

 Project emissions to 2018 – the analysis of potential reductions was based on the projected 2018

emission level. The year 2018 was chosen as a conservative date by which new control technologies

could have been installed. The inventory was also disaggregated from the national level in the EPA

inventory to the seven regions used in the U.S. EIA’s oil and gas data to provide regional reporting.

 Identification of major sources and key mitigation options – the next step was to identify the

largest emitting sources in the projected 2018 inventory and the mitigation options that would be

most effective and cost‐effective for these sources.

 Characterization of emission reduction technologies – a key part of the study was to review and

update information on the cost and performance of the selected mitigation technologies.

Information was gathered from equipment manufacturers, oil and gas companies, and other

knowledgeable parties.

 Development of the marginal abatement cost curves – the technology information was applied to

the emissions inventory to calculate the potential emission reduction and cost. The results were

displayed in a series of marginal abatement cost curves.

The key steps are discussed further in the following sections.

                                                            

7 U.S. EPA, “Inventory of U.S. Greenhouse Gas Emissions And Sinks: 1990‐2011”,

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html 8 http://www.epa.gov/ghgreporting/   9 Allen, David, et. al., “Measurements of Methane Emissions at Natural Gas Production Sites in the United States”.

10.1073/pnas.1304880110
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3.2. Development of the 2011 Emissions Baseline

The development of the 2011 Baseline takes as its starting point the U.S. EPA’s Inventory of U.S.

Greenhouse Gas Emissions and Sinks: 1990 – 2011 published in 2013 with data for 201110, specifically

the portion on methane from Natural Gas and Petroleum Systems. While the EPA Inventory is the most

comprehensive source for this type of information, it is designed to be a planning and reporting tool

rather than the basis for this type of granular analysis. Therefore ICF developed a new 2011 Baseline,

adapting the EPA structure to the needs of the analysis and incorporating more recent information. This

was not a complete update of the inventory, which was beyond the scope of this project, but an update

of any sections for which new or better data could be readily identified. The EPA Inventory11 estimates

436 billion cubic feet (Bcf) or 8.4 million metric tonnes of methane emissions for the petroleum and

natural gas sectors including offshore production in 2011. The petroleum and natural gas sectors are

then further divided into the various segments for the natural gas sector (Gas Production, Gathering and

Boosting, Gas Processing, Gas Transmission, Gas Storage, LNG Import/Export, and Distribution) and the

petroleum sector (Oil Production, Transportation, and Refining).

The EPA Inventory breaks out methane emissions for approximately 200 sources, and calculates

uncontrolled emissions using activity factors (e.g., equipment counts) multiplied by emission factors

(average emissions from each source) to estimate the total emissions. The total uncontrolled emissions

are reduced by emission reductions reported primarily from the EPA’s voluntary Natural Gas STAR

Program, plus additional reductions from other sources, such as state regulations.  

The development of the 2011 Baseline relied on the 2011 EPA Inventory and data from several publically

available references. The most common source of updated information was the U.S. EPA’s mandatory

Greenhouse Gas Reporting Rule (GHGRP) subparts C (combustion from stationary sources) and W

(methane emissions from petroleum and natural gas systems). ICF also used information and data from

the U.S. Energy Information Administration (EIA), EPA’s 1996 GRI study of methane emissions12, the EPA

Manual of Emission Factors AP‐4213, various state energy and environmental departments, and the

EDF/University of Texas methane measurement study. Much of this information was not available at the

time that the 2011 EPA inventory was originally developed.

While some source categories increased and some decreased due to these adjustments, the overall

effect was an increase of 2.4% in the net estimated methane emissions from the oil and gas sectors to

                                                            

10 U.S. EPA, “Inventory of U.S. Greenhouse Gas Emissions And Sinks: 1990‐2011”,

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html 11 While the 2013 edition of the Inventory was the current version at the time the study was initiated, EPA has since released

the draft of the 2014 edition. However this study does not address that newer version of the Inventory. 12 http://epa.gov/gasstar/tools/related.html under “Methane Emissions from the Natural Gas Industry” 13 http://www.epa.gov/ttn/chief/ap42/index.html
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446 Bcf (8.6 million metric tonnes) of methane. The estimated emissions from the natural gas sector

were 2% (10 Bcf) lower while the emissions from the oil sector increased by 26% (20 Bcf) compared to

the EPA inventory. Table 3‐1 summarizes the emissions in the 2011 Baseline compared to the 2011 EPA

Inventory.

The changes by industry segment are shown in Table 3‐1.

Table 3‐1 ‐ Summary of 2011 Methane Emissions Baseline  

Segment

2011 EPA Inventory ICF 2011 Baseline

Change (%) (Million

tonnes CH4) (Bcf CH4) (Milliontonnes CH4) (Bcf CH4)

Natural Gas

Gas Production            2.2               113                 2.0               103   ‐9%

Gathering and Boosting              0.5                 24                 0.8                 43   80%

Gas Processing              0.9                 48                 0.8                 44   ‐9%

Gas Transmission         1.7                 87                 1.4                 75   ‐14%

Gas Storage 0.3                 17               0.3                15   ‐11%

LNG 0.1                   5                 0.1                  6   22%

Gas Distribution         1.3                 69                 1.3                 69   0%

Petroleum

Oil Production 1.4 72 1.8 92   27%

Oil Transportation < 0.1 < 1 < 0.1 < 1   1%

Oil Refining < 0.1 1 < 0.1 1   0%

Total Net Gas Emissions 7.0 362 6.8 353   ‐2%

Total Net Oil Emissions 1.4 73 1.8 93   26%

Total Emissions 8.4 436 8.6 446   2.4%

The largest change to the structure of the Natural Gas segment in the 2011 Baseline was breaking out

the Gathering and Boosting segment. This is the segment between onshore Production and either Gas

Processing or Gas Transmission. This segment is included in the onshore Production segment of the EPA
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Inventory based on the 1996 GRI measurement study rather than being fully broken out as a separate

segment. In this study, some sources were moved from Production to the Gathering and Boosting

segment in order to allow them to be analyzed separately for this segment, and new emissions

estimates, for some sources underrepresented in the 2011 EPA inventory, were added. The major

source additions were new estimates of compressor and pneumatic device emissions. In addition,

emissions from condensate tanks were moved from the Production segment to the Gathering and

Boosting segment.

The overall net change to the Natural Gas segment of the U.S. Inventory is a decrease of 2% compared

to the EPA Inventory value. This is the net effect of increased estimates for well head fugitives and

Gathering and Boosting (for compressors and pneumatic devices) and decreases in the estimates for

well completion and workover emissions (based on data and factors from Subpart W) and compressor

exhaust emissions. These changes are discussed in Appendix B.  

The net change to the Petroleum segment of the 2011 Baseline is 26% higher than the EPA Inventory

value. The biggest categories contributing to this increase were the inclusion of stranded gas venting

from oil wells and updated estimates of associated gas flaring estimates. All of these changes are

discussed in more detail in Appendix B.

3.3. Projection to 2018

The 2018 forecast of natural gas and petroleum systems methane emissions starts with the 2011

Baseline described in Section 3.2.  One primary driver for the projecting the 2011 emissions to 2018 was

the U.S. EIA’s Annual Energy Outlook 2013 and 2014 Early Release. ICF also relied upon a 2011 study for

the INGAA Foundation14 that forecast requirements for selected infrastructure and equipment for the

natural gas and petroleum industry.  In addition, expected emission reductions as a result of NSPS

Subpart OOOO were incorporated into the forecast. Without the NSPS, emissions grow from 446 Bcf in

2011 to 491 Bcf in 2018. With the NSPS adjustments, total emissions are projected to grow by 4.5% to

466 Bcf through 2018. Almost all of this growth is from the oil sector whereas the net emissions for the

gas sector are almost unchanged (Figure 3‐1). Growth from new sources in the gas sector is offset by

NSPS reductions, and reductions from existing sources such as continuing replacement of cast iron

mains and turnover of high‐emitting pneumatic devices. Despite the overall growth, nearly 90% of the

emissions in 2018 come from existing sources (sources in place as of 2011) as shown in Figure 3‐2.

                                                            

14 North American Midstream Infrastructure Through 2035 – A Secure Energy Future, Prepared for the INGAA Foundation, ICF

International, 2011.
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Figure 3‐1 – Emission Projection to 2018 – (Including Offshore)

Figure 3‐2 ‐ Distribution of Emissions in 2018
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The projection also disaggregated the national level emissions estimate of the 2011 inventory to regions

used by the EIA to report oil and gas data (Figure 3‐3). The details of the analysis are discussed in

Appendix C.

Figure 3‐3 ‐ EIA Oil and Gas Regions

3.4. Identification of Targeted Emission Sources

Table 3‐2 summarizes the largest emitting source categories in the projected 2018 emissions for the oil

and gas sectors by major source category. Due to the lack of specific data on the emission sources for

offshore oil and gas production, the study focused on onshore production and offshore emissions are

excluded from this list. The top 22 source categories account for 80% of the total 2018 onshore methane

emissions of 404 Bcf and the remaining 100+ categories account for 1% or less of the total emissions

each. Although these source categories were not included in this analysis due to their small size, there

are demonstrated methane reduction technologies that can provide cost‐effective reductions for many

of them.  

Figure 3‐4 shows the distribution of sources graphically. Fugitive emissions are the largest emission

source category overall. Vented emissions from pneumatic controllers and pumps are also significant as

is vented associated gas from oil well completions and production. Venting from wet seal centrifugal

compressors is also a large source.
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Table 3‐2 ‐ Highest Emitting Onshore Methane Source Categories in 2018

Source

2018

Emissions

(Bcf)

Percent of

Total

Cumulative

Bcf

Cumulative

%

Reciprocating Compressor Fugitives 53.8 13% 53.8 13%

High Bleed Pneumatic Devices 28.7 7% 82.5 20%

LDC Meters and Regulators 28.7 7% 111.2 28%

Centrifugal Compressors (wet seals) 24.0 6% 135.3 33%

Gas Engine Exhaust 22.2 5% 157.5 39%

Well Fugitives 20.8 5% 178.3 44%

Reciprocating Compressor Rod Packing 17.6 4% 195.9 48%

Liquids Unloading ‐ Wells w/ Plunger Lifts 13.2 3% 209.1 52%

Intermittent Bleed Pneumatic Devices 13.0 3% 222.1 55%

Kimray Pumps 11.5 3% 233.6 58%

Oil Tanks 11.5 3% 245.1 61%

Flares 9.0 2% 254.1 63%

Stranded Gas Venting from Oil Wells 8.4 2% 262.5 65%

Intermittent Bleed Pneumatic Devices ‐ Dump Valves 7.7 2% 270.2 67%

Oil Well Completions ‐ with Fracturing 6.9 2% 277.1 69%

Pipeline Leaks (All) 6.7 2% 283.8 70%

Pipeline Venting (Transmission) 6.6 2% 290.4 72%

Centrifugal Compressors (dry seals) 6.4 2% 296.8 73%

Mains – Plastic 6.3 2% 303.2 75%

Mains ‐ Cast Iron 6.3 2% 309.4 77%

Transmission Station Venting 6.2 2% 315.7 78%

Chemical Injection Pumps 5.9 1% 321.6 80%

Residential 5.6 1% 327.2 81%

Gathering and Boosting Stations 5.6 1% 332.8 82%
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Figure 3‐4 ‐ 2018 Projected Onshore Emissions
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3.5. Selected Mitigation Technologies

The following sections describe the mitigation measures included in this analysis to address the high‐

emitting source categories. Some of the most significant measures are discussed in greater detail in

Appendix D. Much of the cost and performance data for the technologies is based on information from

the EPA Natural Gas STAR program15 but has been updated and augmented with information provided

by industry and equipment vendor sources consulted during this study. The discussion is organized

according to the emission source and mitigation option.  

This analysis attempts to define reasonable estimates of average cost and performance based on the

available data. The costs and performance of an actual individual project may not be directly

comparable to the averages employed in this analysis because implementation costs and technology

effectiveness are highly site specific. Costs for specific actual facilities could be higher or lower than the

averages used in this analysis.

Fugitive Emissions – Fugitive emissions are the unplanned loss of methane from pipes, valves, flanges,

and other types of equipment. Fugitive emissions from reciprocating compressors, compressor stations

(transmission, storage, and gathering), wells, and LDC metering and regulator equipment are the largest

combined emission category, accounting for over 120 Bcf, or 30% of the highlighted sources.  

Leak Detection and Repair (LDAR) is the generic term for the process of locating and repairing these

fugitive leaks. There are a variety of techniques and types of equipment that can be used to locate and

quantify these fugitive emissions. Extensive work has been done by EPA and others to document and

describe these techniques, both in the Gas STAR reference materials and in several regulatory analyses.

The potential size and nature of these fugitive emissions can vary widely by industry segment and even

by site. LDAR programs have been analyzed for several recent regulatory initiatives, including for the

EPA’s NSPS Subpart OOOO16 and the current proposed revisions to the Colorado Air Quality Control

Commission Regulation Number 7 (5 CCR 1001‐9)17. This study used both the Colorado regulatory

analysis and the EPA Technical Support Document (TSD) 18 for NSPS Subpart OOOO as the basis for cost

and reduction effectiveness calculations.  

                                                            

15 http://www.epa.gov/gasstar/   16 http://www.epa.gov/airquality/oilandgas/   17 http://www.colorado.gov/cs/Satellite/CDPHE‐AQCC/CBON/1251647985820   18 U.S. EPA, “Oil and Natural Gas Sector: Standards of Performance for Crude Oil and Natural Gas Production, Transmission, and  

Distribution. Background Supplemental Technical Support Document for the Final New Source Performance Standards”.

http://www.epa.gov/airquality/oilandgas/pdfs/20120418tsd.pdf  
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The key factors in the analysis are how much time it takes an inspector to survey each facility, how many

inspections are required each year, how much reduction can be achieved, and how much time is

required for repairs. Research cited by both Colorado and EPA indicates that more frequent inspections

result in greater reductions, summarized as approximately:

 Annual inspection = 40% reduction

 Quarterly inspection = 60% reduction

 Monthly inspection = 80% reduction

ICF adapted the Colorado analysis, which calculates the capital and labor cost to field a full‐time

inspector, including allowances for travel and record‐keeping (Table 3‐3). ICF added additional time for

training. The capital cost includes an infrared camera (which is used to locate fugitive emissions) a truck

and the cost of a record‐keeping system.  The combined hourly cost was the basis for the cost

estimates.

Table 3‐3 ‐ LDAR Hourly Cost Calculation

Labor Capital and Initial Costs

Inspection Staff $75,000 Infrared Camera $122,200  

Supervision (@ 20%) $15,000 Photo Ionization Dector $5,000  

Overhead (@10%) $7,500 Truck $22,000  

Travel (@15%) $11,250 Record keeping system $14,500  

Recordkeeping (@10%) $7,500 Total $163,700  

Reporting (@10%) $7,500

Fringe (@30%) $22,500 Training Hours 80

Subtotal Costs $146,250 Training Dollars $6,223  

Hours/yr 1880 Amortized Capital +Training $44,825  

Hourly  Labor Rate $77.79 Annual Labor $146,250  

Annual Total Cost $191,075  

Total Cost as Hourly Rate $101.64  

Many analyses have used facility component counts and historical data on the time required to inspect

each component to estimate facility survey times. However, the use of the infrared camera technology
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allows much shorter survey times19 and the EPA and Colorado time estimates have been criticized as too

long. The estimates here are based on experience with the infrared camera and are shorter than the

Colorado and EPA estimates that based on component counts.  

ICF then adopted the baseline emission values for wells, gathering and transmission stations, and

processing stations from the EPA analysis. EPA includes three well pad sizes with different baseline

emissions. The EPA analysis did not provide estimates of the distribution of the three sizes for existing

facilities so the middle estimate was used for this analysis. Using the smaller and larger well pad

emission estimates would result in higher and lower emission reduction costs respectively.  

For LDCs, the analysis only includes large meter and regulator facilities. Smaller facilities had a much

higher cost due to the small baseline emissions. The LDC costing was done using the same operator and

capital costs as for the upstream and midstream facilities. The baseline emission factors for LDCs were

adapted from an EPA Gas STAR document20 which found that on average two 100 Mcf/year leaks were

found at 50% of the facilities and the leaks were reduced by 50% through the program.

Table 3‐4 summarizes the assumptions for the overall LDAR calculation. This analysis assumes quarterly

emission surveys for all facilities. The reduction is assumed to be 60%, which is consistent with data

presented in the NSPS TSD and Colorado analysis. In addition to the surveys, the estimate includes one

initial visit to each site to inventory the equipment (equivalent hours to two inspection visits for each

site with cost averaged over five years) and additional visits for repairs. Gas processing plants are

already subject to some LDAR requirements for conventional pollutants, which result in co‐benefit

methane reductions. The miscellaneous fugitive emissions for gas processing were below the size

threshold for this analysis but the costs developed here for gas processing are applied to compressors in

that segment.

Some repairs can be made at the time of the survey, such as tightening valve packing or flanges but

others will require additional repair time. This analysis assumes repair time equivalent to three survey

visits for each facility for repairs each year. The capital cost of larger repairs is not included on the

assumption that these repairs would need to be made anyway and the LDAR program is simply alerting

the operator to the need. The time for repairs is consistent with the low end of the Colorado analysis

that was derived based on component counts and leak rates. This lower repair estimate takes into

account that:

 These are average values across facilities – not every facility will require repairs.

                                                            

19 Robinson, D, et. al., “Refinery Evaluation of Optical Imaging to Locate Fugitive Emissions”. Journal of the Air & Waste

Management Association. Volume 57 June 2007. 20 EPA Gas STAR “Directed Inspection and Maintenance at Gate Stations and Surface Facilities”.

http://epa.gov/gasstar/documents/ll_dimgatestat.pdf  
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 These are average values over time – not every facility will need repairs every year while being

monitored on a continuing basis.

 Some or all of cost of major repairs is assumed to be part of regular facility maintenance.

Table 3‐4 – Cost Calculation – Quarterly LDAR

Well Pads Gathering Processing Transmission LDC

Methane Mcf/yr              440           1,676         2,448               4,671   150

% Reduction 60% 60% 60% 60% 60%

Reduction Mcf              264           1,006         1,469               2,803          90  

Hours each Inspection 2.7 8 8 8 2

Frequency (per year) 4 4 4 4 4

Annual  Inspection Cost $1,084 $3,252 $3,252 $3,252   $813  

Initial Set‐Up $108 $325 $325 $325   $81  

Repair Labor Cost $813 $2,439 $2,439 $2,439   $407

Total Cost/yr $2,006 $6,017 $6,017 $6,017   $1301

Recovered Gas Value* $1,340 $5,105 $7,455 $12,416   $399  

Net Cost $666 $912 ‐$1,438 ‐$6,399 $902  

Cost of Reduction ($/Mcf methane reduced)

Without Gas Credit $7.60 $5.98 $4.10 $2.15   $14.45  

  

With Gas Credit $2.52 $0.91 ‐$0.98 ‐$2.28 $10.03  

    *Gas at $4/Mcf

The value of reduced gas losses is credited to the program for the upstream segments.  These final

reduction cost values were used for the analysis.

Reciprocating Compressor Rod Packing – Reciprocating compressors are used in most segments of the

natural gas and oil industry, though much less commonly in local gas distribution than in other

segments. Rod packing systems are used to maintain a seal around the piston rod, minimizing the

leakage of high pressure gas from the compressor cylinder, while still allowing the rod to move freely

(Figure 3‐5). However, some gas still escapes through the rod packing, and this volume increases as the

packing wears out over time, potentially to many times the initial leak rate. There is no standard

optimum interval to replace the rod packing, but the NSPS Subpart OOOO requires rod packing in new
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reciprocating compressors in the production and processing sectors to be replaced every 26,000 hours

of operation (approximately every three years).

Figure 3‐5 ‐ Reciprocating Compressor Rod Packing

Industry reports that the rod packing for compressors at gas processing plants and some transmission

stations is routinely replaced at least that frequently as part of routine maintenance. However, it is

believed that rod packing in the production and gathering and boosting sectors is replaced less

frequently. This is due, in part, to several factors, including the remote location of these compressors,

the lack of a back‐up compressor for use during compressor downtime, and because many of the

compressors in these sectors are leased rather than owned. This analysis assumes a requirement to

replace rod packing for all reciprocating compressors every 26,000 hours of operation.

Gas STAR data21 indicate that rings (the compressor packing) cost between $300 and $600 per cylinder

and $1,000 to $2,500 per compressor to install. Industry sources for this study put the cost at $5,000 per

cylinder, which was adopted for this analysis. The Technical Support Document (TSD) for NSPS Subpart

OOOO provides a detailed analysis of rod packing replacement. The emissions from new rod packing are

estimated in the TSD at 11.5 standard cubic feet per hour (scfh). Baseline emissions for rod packing are

estimated at approximately 57 scfh, however the age of the packing at that time is not stated. There is

little data on the emissions from rod packing over time but reductions for this mitigation option come

from replacing the rod packing at a shorter interval than currently being practiced at given facility.

                                                            

21 “Reducing Methane Emissions From Compressor Rod Packing Systems”

http://www.epa.gov/gasstar/documents/ll_rodpack.pdf  
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For this analysis it was assumed that the facility currently replaces the rod packing every five years and

that the interval is reduced to three years (26,000 hours). It was assumed that the new rod packing

emits 11.5 scfh and the emissions increase linearly to 57 scfh after three years and increase linearly

thereafter. Comparing the emissions under this scenario for 15 years, the three year replacement

schedule would emit 35% less than the five year replacement schedule.  In addition, the cost of rod

packing replacement would be 66% greater for the three year replacement schedule than the five year

schedule. As noted above, it was assumed that rod packing is already changed on this schedule in many

processing plants and some transmission stations, so the applicability was reduced to 25% for

processing and 70% for transmission, storage and LNG. The assumptions are summarized in Table 3‐5.

Table 3‐5 ‐ Assumptions for Rod Packing Replacement

Centrifugal Compressors (wet seals) – The seals in a centrifugal compressor perform a similar function

to the rod packing in a reciprocating compressor – allowing the rotating shaft to move freely without

allowing excessive high pressure gas to escape (Figure 3‐6). Centrifugal compressors with wet seals use

circulating oil as a seal against the escape of high pressure gas, and the oil entrains some of the gas as it

circulates through the compressor seal. This gas must be separated from the oil to maintain proper

operation (called “degassing the seal oil”), and the gas removed from the seal oil is typically vented to

the atmosphere. 22 These emissions can total 30,000 Mcf/year or more. While wet seals can be replaced

by dry seals that do not use oil and do not vent significant amounts of gas, this is an extremely expensive

process. A lower cost option is to capture and use the entrained seal oil gas rather than venting it. This

technology currently exists at several compressor stations that had such systems installed as original

equipment, but it has not been applied commercially as a retrofit. However, the equipment needed for a

retrofit is commercially available. The measure modeled here is to apply this technology as a retrofit.

This is described as one of the case studies in section 5.1 where the capital cost is estimated at $33,700

for a 99% reduction. Because this technology has not been commercially demonstrated as a retrofit, the

analysis assumed a conservative cost of $50,000 and 95% reduction, yielding a cost‐effectiveness of  

‐$4.87/Mcf with credit for recovered gas or $0.21/Mcf without recovery. Although the gas can be re‐

captured, it may be difficult to use it productively, as this depends on both the pressure of the captured

                                                            

22 Replacing Wet Seals with Dry Seals in Centrifugal Compressors  http://www.epa.gov/gasstar/documents/ll_wetseals.pdf  

Capital Cost

per

Compressor

Percent

Reduction

Mcf

Reduced/year

Lifetime

(years)

Cost w/o Gas

Credit

$6,000 35% 350 3 $6.89/Mcf
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gas and whether a need for the gas exists. The applicability is therefore discounted by 10% to 25%

depending on the industry segment.

Figure 3‐6 ‐ Wet Seal Compressor Schematic

Pneumatic Devices – Pneumatic devices use the pressure of the natural gas stream to operate various

control functions, such as adjusting valves to maintain proper pressure, actuating liquid level and

temperature controllers, etc. Some devices require a continuous small discharge of gas as part of the

controller function. These types of devices are designated as either low bleed devices (emitting < 6

scf/hr) or high bleed devices (emitting ≥6 scf/hr, but typically much more – often more than 30 scf/hr).

In addition to these two categories, there are intermittent bleed devices that are designed to discharge

gas only when they are actuating. These types of pneumatic devices can have emissions anywhere

between high and low bleed controllers. One common device is an intermittent level control device

(“dump valve”) that emits gas only when actuated and typically has emissions similar to low bleed

controllers.  

The EPA GHG Reporting Program Subpart W provides information on pneumatic controllers that can be

used to estimate the distribution of these devices in each segment. This analysis is discussed in Appendix

B and, for example, yields a distribution of 10% high bleed, 50% intermittent bleed, and 40% low bleed

devices for the Production segment. Further analysis was performed to estimate the distribution of

higher‐emitting intermittent devices vs lower‐emitting dump valves, also discussed in Appendix B. For

the Production segment, it was estimated that 75% of the intermittent bleed devices are lower‐emitting

dump valves.  

The two mitigation options considered in the study are:

 Replace high bleed controllers with low bleed controllers.
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 Replace high‐emitting intermittent controllers (not dump valves) with low bleed controllers.

Some components require high bleed controllers for operational reasons, primarily for fast‐acting valves

associated with compressors, so the measure was applied to only 60% of the inventory of high bleed

controllers in transmission, storage, and LNG, 80% in processing and 90% of the high bleed controllers in

other segments. Although there are lower cost estimates from Gas STAR and vendors, this measure

assumed a cost of $3,000 per replacement based on industry comments. Both options yield a greater

than 90% reduction. This yields a reduction cost of ‐$3.08/Mcf of methane for replacement of high bleed

pneumatics and $0.58/Mcf of methane for replacement of intermittent bleed pneumatics, including a

credit for recovered gas, where applicable.

Chemical Injection Pumps – These are small pumps used to inject various chemicals, most commonly

methanol, into gas wells to prevent well freeze‐up during cold weather. They are typically driven by gas

pressure and vent gas when they operate. The suggested mitigation measure is to replace the gas‐driven

pumps with electric pumps driven by solar energy. (Well pads and many gathering/boosting stations

typically do not have electricity.) This technology has been demonstrated by Gas STAR Partners and

industry respondents indicated that it is gaining broader acceptance. Replacement results in elimination

of the methane emissions, and the gas‐driven pump could be left in place as a back‐up. The cost of the

measure was estimated at $5,000 per pump, yielding an annual reduction of 180 Mcf/year and a cost‐

effectiveness of ‐$0.22/Mcf of methane reduced with the recovered gas credit. Local conditions or

operational considerations may limit the applicability so the measure is applied to 80% of the inventory.

Oil and Condensate Tanks without Control Devices – Crude oil and liquid condensate production at

wells and gathering facilities is stored in fixed roof field tanks and dissolved gas in the liquids is released

and collects in the tank space above the liquid. Ultimately, this gas is often vented to the atmosphere.

Vapor recovery units (VRUs) collect and compress this gas, which can then be re‐directed to a sales line,

used on‐site for fuel, or flared. Based on Gas STAR and industry data, the capital cost of this measure is

assumed to be $100,000 with an operating cost (electricity) of $7,500 per year and a reduction of 13,410

Mcf per year. This yields a reduction cost of ‐$0.51/Mcf if the gas is recovered for sale or $4.57/Mcf if it

is flared. Some facilities already have VRUs and they may not be effective where the liquid volume is

small or the methane content is low. Also VRUs require electricity, which is not available at all sites. For

these reasons, the measure is applied to 50% of the remaining oil and 25% of the remaining condensate

tank emission inventory.  

Kimray Pumps – Kimray pumps are gas‐powered pumps used to circulate glycol in gas dehydrators. They

are larger than the chemical injection pumps and vent larger amounts of gas. In the facilities that have

electricity, these could be replaced by electric motor‐driven pumps. The replacement cost is estimated

at $10,000 per pump based on vendor and Gas STAR data. Unlike the solar pumps, these pumps will

require grid electricity, estimated to cost $2,000 per year. Based on a 5,000 Mcf emission reduction, the

cost‐effectiveness is ‐$4.17/Mcf of methane with credit for gas recovered and it is applied to 50% of the

inventory.
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Liquids Unloading – Liquids unloading is the process of removing liquids from the bottom of gas wells

when the accumulation is impeding the gas production. The liquids must be removed in order to allow

effective production from the well. Historically this has been practiced on older, vertical wells whose

pressure has declined.  

While there are a variety of methods of removing this liquid, one method is by venting or “blowing” the

well to the atmosphere, using the pressurized gas in the reservoir to lift and blow the liquids out of the

well. The frequency and duration of liquids unloading depends on the well and reservoir conditions,

however, venting is not a very effective method of removing the liquids. Further, since the well is vented

to the atmosphere, it results in large methane emissions and losses of gas. There are multiple methods

of removing liquids without venting, but in standard practice, the primary goal of liquids unloading is to

improve well performance, not reduce emissions. The choice of method is normally a function of the

cost versus the value of improved well performance. This topic is further discussed in section 5.4.

Figure 3‐7 ‐ Plunger Lift Schematic

Plunger lifts are devices that fit into the well bore and use the

gas pressure to bring liquids to the surface more efficiently

while controlling and limiting the amount of venting (Figure

3‐7). If there is sufficient reservoir pressure, the gas can be

directed to the sales line with no venting. If there is insufficient

pressure to direct the gas to the sales line and the gas must be

vented, the emissions can still be reduced by 90% compared to

uncontrolled venting. Plunger lifts are a relatively low cost

option and can be implemented in a relatively simple manual

control method or more complex automated installations. That

said, the technology does have limitations. The well must have

sufficient pressure to operate the plunger and older wells may

require clean‐outs or work‐overs to allow the plunger to

operate. Further, not all well types can use a plunger lift for

liquids removal.  

Gas STAR estimates for plunger lift installation range from $2,500 to $10,00023 but industry commenters

on this study cited costs in the range of $15,000 and pointed out that well treatments and clean‐outs

may be required before plunger lifts can be installed. This analysis assumes a cost of $20,000, including

the allowance that some wells may need clean‐outs or other work.  Gas STAR Partners report reductions

of venting emissions of 90% for plunger lifts that do not go to the sales line. In addition, they report that

liquids unloading can increase production by anywhere from 3 to 300 thousand cubic feet per day

                                                            

23 Installing Plunger Lift Systems In Gas Wells http://epa.gov/gasstar/documents/ll_plungerlift.pdf  
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(Mcf/day). The increased productivity of the well is the primary goal of liquids unloading and the higher

gas production can pay for the cost of plunger lifts many times over. However, the subsequent increase

in well productivity is difficult to predict and is not included in this analysis. Without credit for the

productivity increase, the cost‐effectiveness breakeven point is at about 1,200 Mcf/year of venting,

estimated here as a reduction cost of ‐$0.05/Mcf reduced.  

If the well does not have sufficient pressure or cannot support a plunger lift, there are a variety of

mechanical pumping technologies that can be employed to remove liquids. However, these are much

more expensive and while they may have a positive payback for increasing well production, they most

often do not purely for the methane emission reduction. Moreover, the methane reduction value only

applies if the well would otherwise be vented. As the well pressure declines, venting becomes a

diminishingly effective option. In addition, it is not clear how effective venting will be at removing liquids

from long horizontal wells that are now being drilled. It may be that venting for liquids removal will

continue to be primarily focused on older, vertical wells.

The GHG Reporting Program Subpart W provides data on wells that are venting for liquids unloading

with and without plunger lifts. The data for 2012 show over 53,000 wells venting an average of 167 Mcf

per year without plunger lifts and over 74,000 wells with plunger lifts venting an average of 277 Mcf per

year. Wells that use plunger lifts and send the gas to the sales line do not have any venting emissions

and do not report to this part of Subpart W. While it seems counterintuitive that wells with plunger lifts

that vent would be emitting more than those without plunger lifts, ICF interprets this information to

indicate that most of the wells with the largest venting emissions have already installed plunger lifts

while most of the remaining wells are venting infrequently or venting small volumes that do not justify

the cost of installing plunger lifts. That said, there are a small number of wells without plunger lifts that

report larger venting emissions and account for a disproportionate fraction of the venting emissions for

wells without plunger lifts, approximately 36% of total venting emissions. Installing plunger lifts on these

wells could be cost‐effective and create significant emission reductions.  Because plunger lifts are not

applicable to all wells, the measure was applied to 30% of this emission segment for the analysis.

As noted above, wells with plunger lifts also report significant emissions from venting. Operation of a

plunger lift is complex and its effectiveness as an emission reduction technique depends on many

factors to operate the plunger at the optimum time to maximize production and minimize emissions.

Approaches to plunger lift operation range from ad hoc manual operation, to fixed mechanical timers, to

programmable “fuzzy logic” automated controllers. Specific data on the potential reductions from

optimized plunger lift operation is not available but it is clear from industry experience that an

integrated program of training, technology, and automation can improve the performance of plunger

lifts for both productivity and emission reductions. Consequently, there may be an opportunity for

significant emission reduction through optimization of plunger lifts, which is not included here and

would be additional to the reduction estimates this analysis provides for installation of new plunger lifts.
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Stranded Gas Venting from Oil Wells and Venting of Oil Completion Gas – Oil contains some amount of

natural gas, which is separated at the wellhead. Where there is a gas sales line available, the gas is sent

to sales. When no nearby sales line exists, the gas is either vented or flared. This can occur during the

short period after the well is completed or it can continue throughout the life of the well, depending on

the access to gathering infrastructure. While flaring creates CO2 emissions from combustion and some

unburned methane, the total greenhouse gas emissions are much lower than venting the methane, with

its higher global warming potential.

The measure modeled here is flaring of the gas on the assumption that the gas would be sent to sales if

the infrastructure were available. While Gas STAR and vendor information cite relatively low‐cost flares,

industry cited more expensive flaring equipment that is being required to meet regulatory

requirements. ICF adopted this higher estimate, assuming a capital cost of $50,000 and a fuel cost of

$6,000 for ignition. The flare is assumed to be 98% effective. The cost‐effectiveness depends on the

amount of gas flared, which is lower for completion emissions than flaring of associated gas on a

continuous basis. The cost‐effectiveness is estimated at $1.86/Mcf of methane for completion gas and

$0.26/Mcf of methane for flaring of stranded associated gas.

Pipeline Venting (Routine Maintenance/Upsets) – These emissions occur when companies take

sections of pipeline out of service for maintenance and vent the gas that is in the pipeline. These

emissions can be reduced for planned shutdowns (not emergency shutdowns) either by using the

pipeline compressors to pump down the gas in the affected section or by using leased mobile

compressor units when the pipeline compressors are not appropriately located. The analysis assumed a

combination of both measures applied to 10 mile sections of pipeline, based on a Gas STAR analysis24.

Using the pipeline compressor requires no capital cost but only the fuel cost to pump down the line. The

second option was to lease a portable compressor and pay for the delivery and fuel consumption. The

reductions are generally greater using a portable compressor, as these compressors can generally bring

the pipeline down to a lower pressure than the inline compressors alone. Assuming that a leased

compressor is used for one out of five occurrences, the cost was $0.41/Mcf of methane reduced, with

no fuel recovery credit.

Transmission Station Venting – The major reason for transmission station venting is the government‐

required annual testing of relief valves to assure emergency shutdown (ESD) functions properly. During

the standard practice in testing these systems, gas is vented from all of the relief valves at the station for

a few minutes. These emissions can be avoided by putting quick opening closures over the relief valve to

contain the gas when the relief valve is cycled open and closed, but allow a fast response if there is an

emergency during the test. While Gas STAR has estimated the cost of this measure at $8,000, industry

                                                            

24 “Using Pipeline Pump‐Down Techniques To Lower Gas Line Pressure Before Maintenance”.

http://www.epa.gov/gasstar/documents/ll_pipeline.pdf  
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respondents suggested a cost of $30,000 for a full station redesign. The cost adopted for the analysis

was $15,000 assuming a change in procedure but no station redesign, yielding a cost‐effectiveness of

$0.98/Mcf with no gas recovery credit.

Summary

Table 3‐6 summarizes the mitigation measures applied in the analysis for each major emission source.

Table 3‐7 summarizes the characteristics of the measures modeled. The cost‐effectiveness ($/Mcf of

methane removed) was calculated with and without credit for any recovered gas. The annual cost was

calculated as the annual amortized capital cost over the equipment life plus annual operating costs. This

was divided by annual methane reductions to calculate the cost‐effectiveness without credit for

recovered gas. Where gas can be recovered and monetized by the operating company, the value of that

gas was subtracted from the annual cost to calculate the cost‐effectiveness with credit for recovered

gas. The costs shown here are the baseline costs, which are adjusted for regional cost variation in the

analysis. As noted earlier, these are average costs that may not reflect site‐specific conditions at

individual facilities.

   
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Table 3‐6 ‐ Summary of Mitigation Measures Applied

Source Mitigation Measure

Oil/Condensate Tanks w/o Control Devices Vapor Recovery Units

Liquids Unloading ‐ Wells w/o Plunger Lifts Plunger lifts

High Bleed Pneumatic Devices Replace with low bleed devices

Intermittent Bleed Pneumatic Devices Replace with low bleed devices

Chemical Injection Pumps Solar electric pumps

Kimray Pumps Electric pumps

Pipeline Venting (Routine Maintenance/Upsets) Pipeline pump‐down

Centrifugal Compressors (wet seals) Wet seal gas capture

Transmission Station Venting Gas capture

Oil Well Completions ‐ with Fracturing Flaring

Stranded Gas Venting from Oil Wells Flaring

Reciprocating Compressor Rod Packing Rod packing replacement

Reciprocating Compressor Fugitives Leak detection and repair  (LDAR)

Compressor Station Fugitives Leak detection and repair  (LDAR)

Well Fugitives Leak detection and repair  (LDAR)

Gathering Station Fugitives Leak detection and repair  (LDAR)

Large LDC Facility Fugitives Leak detection and repair (LDAR)
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Table 3‐7 ‐ Summary of Mitigation Measure Characteristics

Name Capital Cost Operating Cost Percent Reduction $

w/ 

Early replacement of high‐bleed devices with low‐bleed devices $3,000 $0 97% Early replacement of intermittent‐bleed devices with low‐bleed devices $3,000 $0 91% Replacement of Reciprocating Compressor Rod Packing Systems $6,000 $0 35% Install Flares‐Completion $50,000 $6,000 98% Install Flares‐Venting $50,000 $6,000 98% Liquid Unloading ‐ Install Plunger Lift Systems in Gas Wells $20,000 $2,400 95% Install Vapor Recovery Units on Tanks $100,000 $7,500 95% Transmission Station Venting ‐Redesign Blowdown Systems /ESD Practices $15,000 $0 95% Replace Pneumatic Chemical Injection Pumps with Solar Electric Pumps $5,000 $75 100% Replace Kimray Pumps with Electric Pumps $10,000 $2,000 100% Pipeline Venting ‐ Pump‐Down Before Maintenance $0 $12,000 80% Wet Seal Degassing Recovery System for Centrifugal Compressors $50,000 $0 95% LDAR Wells $169,923 $146,250 60% LDAR Gathering $169,923 $146,250 60% LDAR Large LDC Facilities $169,923 $146,250 60% LDAR Processing $169,923 $146,250 60% LDAR Transmission $169,923 $146,250 60% 
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3.6. Source Categories Not Addressed

Several source categories with relatively large emissions were not addressed in the analysis. The sources

and the reasons for their treatment are summarized below.  

 Off‐shore oil and gas production – As noted earlier, the EPA inventory provides very limited data on

offshore emissions, which were not adequate to apply the methodology used for other sources. This

is an area in which further analysis would probably yield additional opportunities for reduction.

 Cast‐iron gas mains – Cast‐iron mains have been identified is a significant emission source, however

they are primarily located in congested urban areas where replacement or repair  is very expensive,

reported as $1 million to $3 million per mile. This makes for a very expensive control option based

purely on emission reduction. Moreover, these expenditures must be approved by state utility

commissions, whose purview typically does not extend to environmental remediation of this type.

That said, approximately 3% of cast iron mains are being replaced each year for safety reasons, so

the emissions are gradually declining. New technologies could reduce the cost of reduction in the

future.

 Engine exhaust – The exhaust from gas‐burning engines and turbines contains a small amount of

unburned methane from incomplete combustion of the fuel. While it is a small percentage, it is

significant in aggregate. Oxidation catalyst devices are used to reduce unburned emissions of other

hydrocarbons in the exhaust but they are not effective at reducing emissions of methane due to its

lower reactivity. However, new catalysts are being developed, in part for natural gas vehicles, which

may be applicable to these sources. This is a topic for further research and technology deployment.

 Other sources – There are additional cost‐effective measures for methane reduction that have been

identified by the EPA Gas STAR program and others. They are not included here because this report

focuses only on the largest emitting sources. However, their omission should not be taken to

indicate that the measures listed here are the only cost‐effective methane reduction measures.
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4. Analytical Results

4.1. Development of Emission Control Cost Curves

With the 2018 Projected Baseline established and mitigation technologies identified and characterized

for the major emitting sectors, emission cost reduction curves were calculated for a variety of scenarios.

The model developed for this task includes the individual source categories for each segment of the oil

and gas industry by region. Mitigation technologies can be matched to each source by region and/or

individual source applied. The model can also specify what portion of each source population the

measure applies to and whether it applies to new (post‐2011), existing (as of 2011), or all facilities. The

model calculates the reduction achieved for each source and calculates the cost of control based on the

capital and operating costs, the equipment life, and where appropriate, the value of recovered gas. Key

global input assumptions include: whether a particular segment is able to monetize the value of

recovered gas, the value of gas, and the discount rate/cost of capital. A construction cost index is used

to account for regional cost differences, which are 13% to 24% higher for continental U.S. locations

other than the baseline Gulf Coast costs.

The results are presented primarily as a Marginal Abatement Cost Curve (MAC curve), shown in Figure

4‐1.  This representation shows the emission reductions sorted from lowest to highest cost‐of‐reduction

and shows the amount of emission reduction available at each cost level. The vertical axis shows the

cost per unit in $/Mcf of methane reduced. A negative cost‐of‐reduction indicates that the measure has

a positive financial return, i.e. saves money for the operator.  The horizontal width of the bars shows the

amount of reduction. The area within the bars is the total cost per year. The area below the horizontal

axis represents savings and the area above the axis represents cost. The net sum of the two is the total

net cost per year.  
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Figure 4‐1 ‐ Example MAC Curve

4.2. Emission Reduction Cost Curves

This section presents the results of the cost curve analysis. The curves represent different views of a

potential emission control scenario in 2018 based on measures installed between 2011 and 2018. The

emission reduction costs are the annual costs per Mcf of methane reduced. This should not be confused

with cost per Mcf of natural gas produced, which is an entirely different metric. In the cases shown here,

the total annual cost of reductions divided by total U.S. gas production is less than $0.01/Mcf of gas

produced in all cases.  

There are several caveats to the results:

 The 2011 EPA inventory is the best starting point for analysis, but it is based on many assumptions

and some older data sources. Although the inventory is improving with new data, it is designed to

be a planning and reporting document and is imperfect, especially at the detailed level, for a

granular analysis of this type.

 Emission mitigation cost and performance are highly site specific and variable. The values used here

are estimated average values.

 The analysis presents a reasonable estimate of potential cost and magnitude of reductions within a

range of uncertainty.
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The base case assumption for the results in this section assumes a $4/Mcf price for recovered gas and a

10% discount rate/cost of capital for calculating the cost of control.  Additional sensitivity and

alternative cases are shown in Appendix A.

Figure 4‐2 shows the national aggregate MAC curve for the baseline technology assumptions by source

category. It shows the reductions achievable from each source with the relevant emission control

measure. These results are aggregated across industry segments, so the “reciprocating compressor

fugitives” block, for example, includes the cost and reductions from the source among all segments. The

variations between regions and between segments for a given technology are averaged for each block.

Figure 4‐2 – National Aggregate MAC Curve for Baseline Technology Assumptions

The total reductions are 163 Bcf of methane per year or 40% of the 2018 onshore emissions from the oil

and gas industries. The total annualized cost to achieve those reductions is $108 million/year or

$0.66/Mcf of methane reduced. This total annual cost is the net of the $164 million annual savings

(green bars below the axis) and $272 million annual cost (blue bars above the axis). The chart shows

which sources and technologies have the lowest cost‐of‐control (height ‐ vertical axis) and the greatest

reduction (width – horizontal axis). The results are also summarized in Table 4‐1. The cost ranges from  

‐$4.05/Mcf methane reduced for replacement of Kimray pumps with electric pumps to $19.75/Mcf

methane reduced for LDAR at large LDC facilities. These costs include regional cost adjustments and are

therefore different than the baseline costs listed in Section 3. Credit for recovered gas accrues to all

sectors except transmission and LDCs, which are limited by rate regulation from monetizing the
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emission reductions. The reductions from VRUs on condensate tanks are included but are too small to

appear on the curve.

Table 4‐1 also shows the estimated initial capital cost. This is a top‐down estimate based on the

projected reductions and the capital cost per measure so the costs are less certain than in a bottom‐up

costing, particularly with respect to differences between segments. The total initial capital cost is

estimated at $2.2 billion.  

Table 4‐1 – Annualized Cost and Reduction and Initial Capital Cost

Source/Measure

Annualized

Cost

($ million/yr)

Bcf Methane

Reduced/yr

$/ MCF

Methane

Reduced

Initial Capital

Cost

($ million)

Kimray Pumps‐‐Electric Pump ‐$23.4 5.8 ‐$4.05 $23.1

Centrifugal Compressors (wet seals)‐‐Gas Capture ‐$58.7 19.1 ‐$3.07 $79.6

Compressor Stations (Storage)‐‐LDAR ‐$4.5 1.5 ‐$3.03 $2.8

High Bleed Pneumatic Devices‐‐Low Bleed ‐$67.4 25.4 ‐$2.65 $246.8

Reciprocating Compressor Fugitives‐‐LDAR ‐$10.5 32.3 ‐$0.33 $61.6

Condensate Tanks w/o Control Devices‐‐VRU $0.1 0.4 $0.21 $8.5

Stranded Gas Venting from Oil Wells‐‐Flares $2.4 8.2 $0.30 $228.3

Oil Tanks‐‐VRU $1.8 5.5 $0.33 $105.1

Pipeline Venting‐‐Pump‐Down $2.3 4.2 $0.53 $0.0

Chemical Injection Pumps‐‐Solar Pumps $2.7 4.8 $0.57 $432.0

Liquids Unloading ‐ Uncontrolled‐‐Plunger Lift $1.2 1.6 $0.74 $27.8

Transmission Station Venting‐‐Gas Capture $7.5 5.9 $1.27 $49.4

Gathering and Boosting Stations‐‐LDAR $5.0 3.3 $1.51 $17.7

Intermittent Bleed Pneumatic Devices‐‐Low Bleed $20.9 12.1 $1.72 $455.4

Oil Well Completions ‐ with Fracturing‐‐Flares $14.5 6.8 $2.13 $50.4

Compressor Stations (Transmission)‐‐LDAR $7.7 2.8 $2.79 $5.3

Well Fugitives‐‐LDAR $43.9 12.5 $3.51 $84.4

Reciprocating Compressor Rod Packing‐‐Rod Packing $22.3 3.6 $6.11 $182.3

LDC Meters and Regulators‐‐LDAR $140.6 7.1 $19.75 $91.5

Grand Total $108.3 162.9 $0.66 $2,151.9
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Figure 4‐3 shows the emission reductions by major category. Reducing fugitive emissions is the main

opportunity for reduction, followed by reduced venting and replacement of pneumatic devices. While

those categories include a wide range of sources, wet seal centrifugal compressors represents a single

equipment type and mitigation measure.

Figure 4‐3 ‐ Distribution of Emission Reduction Potential

   
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Figure 4‐4 shows the reduction in methane emissions by industry segment for the same case. The

transmission and distribution sectors are not able to monetize their reductions and therefore have a net

positive cost. The LDC segment has only one measure and is the highest cost. The costs for the other

sectors depend on the particular mitigation options available in each and their aggregate cost. The oil

and gas production segments plus gas transmission account for almost 70% of the total reductions.

Figure 4‐4 ‐ Emission Reduction by Industry Segment

Table 4‐2 shows the initial capital cost by industry segment. The majority of the costs, like the majority

of the reductions, are in the oil and gas production segments, followed by transmission. Again, this

aggregation by segment is approximate due to the top‐down methodology used to develop the

estimates.

   
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Table 4‐2 ‐ Initial Capital Cost by Industry Segment

Segment Initial Capital Cost

($ million)

Gas Processing $85.3

Gas Storage $42.1

Gathering and Boosting $106.0

LNG $12.4

Gas Production $707.8

Oil Production $865.6

Gas Transmission $241.2

Gas Distribution $91.5

Grand Total $2,151.9

Figure 4‐5 shows the breakdown of reduction options for the Gas Production segment. Replacement of

high bleed and intermittent bleed pneumatic devices accounts for over half the reductions. LDAR for

reduction of well fugitives is a positive cost and accounts for over a third of reductions. Replacement of

high bleed pneumatics and Kimray pumps are the negative cost (savings) options. The total reduction is

35 Bcf with a net cost of $0.44/Mcf of methane reduced.

Figure 4‐5 – Emission Reductions for the Gas Production Segment
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Figure 4‐6 shows the reductions for the Oil Production segment. Replacement of high and intermittent

bleed pneumatics are significant components, as in Gas Production, accounting for nearly half of the

reductions. In addition, flaring of completion emissions and stranded associated gas are also significant

but no gas is recovered from the flaring. Methane recovery from oil tanks is the other significant

measure for this segment. The total reduction is 39.5 Bcf at a cost of ‐$0.10/Mcf of methane reduced.

Figure 4‐6 ‐ Emission Reductions for the Oil Production Segment

Figure 4‐7 shows the reductions for Gathering and Boosting. LDAR to reduce fugitives at stations and

reciprocating compressors accounts for over half the reductions while electrification of Kimray pumps

accounts for over a third.  The total reduction is 15 Bcf at a cost of ‐$1.97/Mcf of methane reduced.
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Figure 4‐7 ‐ Emission Reductions for the Gathering and Boosting Segment

Figure 4‐8 shows the reductions for the gas transmission segment. LDAR reductions of fugitives from

stations and compressors are the largest components. Capture of degassing emissions from wet seal

centrifugal compressors and reduced venting are the other significant measures. Due to regulatory

limitations, transmission pipelines are not able to monetize emission reductions, so the cost of

reductions is positive for all measures, $2.24/Mcf of methane reduced for 37 Bcf of reductions.

Figure 4‐8 ‐ Emissions Reductions for the Gas Transmission Segment
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As discussed earlier, the baseline cost‐effectiveness assumption is that the value of recovered gas is

recognized in all of the upstream sectors but not in transmission or distribution, due to regulatory

constraints. Figure 4‐9 shows the sector‐wide MAC curve for the base case when the value of the

recovered gas is recognized for all sectors as an economy‐wide value. The order of the measures is

slightly re‐ordered but more importantly, much of the cost curve is shifted downward as a result of

including the full value of the gas recovered. The total net cost now is ‐$150 million/year or ‐$0.92/Mcf.

In other words, if the economic value of all potentially recovered gas is accounted for, onshore

emissions can be cut by over 40% at a net negative cost.

Figure 4‐9 ‐ National Aggregate MAC Curve with Baseline Technology Assumption and Economy‐Wide Value Recognition

Figure 4‐10 shows the MAC curve results by region. The magnitude of the reduction (width of the bar) is

driven by the reduction potential in the region, which is related to the size of the region and the amount

of oil and gas activity. It is also affected by the regional cost adjustments, which add 13% to 24% to the

cost for regions outside the Gulf Coast. The Gulf Coast and Midcontinent account for almost half the

reductions due the large amount of production in those regions. The Northeast also has a large share

because it includes the eastern third of the U.S. and has an increasing amount of production. The cost

(height of the bar) is determined by the mix of control measures within each region. The producing

regions have more upstream measures with lower cost. The West Coast and Northeast have a lower

share of production and a greater share of transmission and distribution sources that cannot monetize

their reductions, and thus have higher average cost.
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Figure 4‐10 ‐ National Aggregate MAC Curve by Region

4.3. Co‐Benefits

Measures that reduce gas emissions will also reduce the emissions of conventional pollutants ‐ volatile

organic compounds (VOCs) and hazardous air pollutants (HAPs) ‐ in the gas as well as methane. Most of

these components are removed from the gas at the gas processing stage so the primary co‐benefits are

at or prior to that stage in the value chain. Figure 4‐11 shows that reductions are 44% of the original

inventory of both pollutants. The net reduction costs are low relative to conventional control programs

due to the economic value of recovered gas: $158/ton for VOCs and $4,147/ton for HAPs, however the

cost‐effectiveness for some individual sources with low emissions is much higher. Moreover, the same

total annual cost ($108 million/year) is applied to the reduction for methane, VOC, and HAPs – that is

allocating the full cost to each pollutant rather than dividing the cost among the pollutants, which would

yield a lower cost of control.
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Figure 4‐11 – Co‐Benefit Reductions of VOCs and HAPs

Figure 4‐12 and Figure 4‐13 show the sources of the co‐benefits for reduction of VOCs and HAPs.  

Figure 4‐12 ‐ VOC Reduction Co‐Benefits
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Figure 4‐13 ‐ Hazardous Air Pollutant Co‐Benefits
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5. Case Studies  

This section provides additional background on two emissions sources that are of particular interest due

to their large emissions and/or opportunity for reduction. The two sources are wet seal centrifugal

compressors and liquids unloading from gas wells.

5.1. Wet Seal Compressor Degassing for Centrifugal Compressors

Centrifugal compressors are used widely throughout the petroleum and natural gas industry. These

compressors can be used in a wide range of applications. Centrifugal compressors have a central

rotating shaft with impellers that act to pressurize and compress the natural gas. These shafts are

powered externally to the compressor casing, meaning that the shaft needs to pass through the casing.

The opening where the shaft passes through the casing creates a path for the pressurized gas to escape.

Different types of seals are used to prevent the gas from escaping.

Wet Seals ‐ Wet seals in centrifugal compressors use a lubricating oil kept at a higher pressure than the

gas in the compressor casing, forming an effective barrier against gas leakage. Very little gas escapes

through the barrier, but a considerable amount gets entrained in the oil that comes in direct contact

with the high pressures gas at the “inboard” (compressor) side. In order to keep the seal oil in good

condition, the seal oil must be purged of natural gas in a process called “degassing.”

During the degassing process, the contaminated seal oil is sent from the seal to a low pressure tank,

called a “flash tank” kept near atmospheric pressure. When the oil/gas mixture enters the tank, the gas

“flashes” out of the oil, effectively separating the gas from the oil. The now clean oil is then sent to a

holding tank to be pressurized and recirculated through the seals. The gas that is removed from the oil is

generally vented to the atmosphere, creating significant methane emissions.  

Dry Seals ‐ The mechanical “dry seal” does not use circulating seal oil but instead operates mechanically

under the opposing force created by hydrodynamic grooves and static pressure as shown in Figure 5‐1.

Dry seals consist of two rings on the compressor shaft where the shaft exits the compressor casing. One

of these is a stationary ring, and one is a rotating ring. When the compressor is not rotating, the

stationary ring in the seal housing is pressed against the rotating ring by springs. When the compressor

shaft rotates, hydrodynamic grooves etched into the surface of the rotating ring direct gas between the

rotating ring and the stationary ring. The opposing force of high‐pressure gas pumped between the rings

and springs trying to push the rings together creates a minute gap between the rings through which

little gas can leak. Further, this gas between the rings means that the rings do not touch during

operation, significantly reducing wear and eliminating the need for a lubricant.
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Since dry seals do not require a lubricant, there are no emissions from degassing. In fact, the only

emissions from the seal are the gas that leaks through the seal itself. According to studies, the leak rate

across dry seals is approximately 3 scfm, substantially lower than the emissions from wet seals, which

range from 40 to 200 scfm.25, 26

Figure 5‐1 ‐ Dry Seals on a Centrifugal Compressor

5.2. Dry Seal Replacement/Retrofit

One option to reduce methane emissions is to use a dry seal compressor instead of a wet seal

compressor. This can be accomplished by either replacing the compressor or retrofitting it to use dry

seals. Both of these options can be viable, depending on the project, but are almost always quite

expensive, usually over $300,000 per compressor. Therefore, this option is often not cost‐effective.  

5.3. Wet Seal Degassing Capture Systems

Another, substantially less expensive option is to install equipment to capture and use or flare the gas

that flashes out during the degassing of the seal oil. This system uses two separators, one at high

pressure, and one at lower pressure. The high pressure separator operates at the seal oil pressure, and

the gas flow is controlled by a critical orifice. This high pressure captured gas is then routed to a seal oil

demister to remove any remaining seal oil before being routed to beneficial use. The oil then flows from

the high pressure separator to the atmospheric degassing separator where the remaining entrained gas

                                                            

25 U.S. EPA. “Replacing Wet Seals with Dry Seals in Centrifugal Compressors.”

http://epa.gov/gasstar/documents/ll_wetseals.pdf 26 Southcott, et. al. “Dry Gas Seal Retrofit.” http://turbolab.tamu.edu/proc/turboproc/T24/T24221‐230.pdf
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is removed and vents to the atmosphere. This volume of gas is usually minimal, as most of the gas can

be removed in the high pressure separator. The regenerated seal oil can then be recirculated back to the

compressor seal oil system. This arrangement is shown Figure 5‐2. These systems have been installed

operated successfully as original equipment at several gas compression stations. Their use as a retrofit

technology is a new application.

Figure 5‐2 Wet seal degassing recovery system for centrifugal compressors (Source U.S. EPA)

Wet seal degassing recovery systems could potentially be installed at most locations with wet seal

centrifugal compressors, though there may be limitations due to site‐specific operating requirements. In

order to implement this system there must be a use for the recovered gas.  Operators have several

options on how to best utilize this gas, and these choices will impact the economics of the project. The

most common options are:

 Use as high pressure turbine fuel (~250 psig)

 Route the recovered gas as low pressure fuel (~50 psig)

 Route back to compressor suction

 Use as a flare sweep gas

Not all of these applications may be available at all sites. In addition, gas recovered from the low

pressure side of the compressor may not be usable for high pressure applications or may require

compression depending on the application.  

5.3.1. Economic Analysis of Installing Wet Seal Degassing Capture Systems

The analysis of a wet seal degassing recovery system should consider the capital and operational costs

along with the methane emissions savings.  Two detailed economic analyses are shown below. The first
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scenario depicts installing the wet seal degassing recovery system on a single centrifugal compressor.

The second illustrates a wet seal degassing recovery system installed at a compressor station with four

centrifugal compressors.

The investment per compressor to use this technology includes the cost of a high pressure seal oil

separator, new piping, pressure and flow controls, and the labor to design and install the equipment. In

most cases, incremental operating and maintenance costs are expected to be minimal. If the gas is to be

used as fuel, a demister will also be required in order to remove any entrained seal oil from the gas that

exits the high pressure separator. If the recovered gas is routed to a higher pressure fuel system, an

additional seal oil high efficiency filter/separator will likely be required to ensure all the oil mist is

removed.

The estimated capital cost for each separator includes the purchase cost of the vessel, piping,

instrumentation, structural support, electrical, painting, shipping, insurance, and installation. Table 5‐1

summarizes these cost estimates (in 2013 U.S. dollars) for each piece of installed equipment in a

degassing recovery system.

Table 5‐1 ‐ Degassing Recovery System Estimated Installation and Equipment Costs

Equipment

Capital Cost –

One Centrifugal

Compressor

Capital Cost –

Compressor Station

(Four Compressors)

Seal‐Oil/Gas Separator* $19,700 $78,800

Seal Oil Gas Demister – Low  Quality

Gas $9,000 $9,000

Seal Oil Gas Demister – High  Quality

Gas $5,000 $5,000

Total $33,700 $92,800

*Assumed two seals per centrifugal compressor and four centrifugal compressors at the station.

An individual high pressure seal oil gas separator costs about $9,850 per seal.

High Pressure Seal Oil Gas Disengagement Separators

For each centrifugal compressor, a seal oil gas separator is to be installed for each seal or pair of seals

(assuming the pair is operating at the same seal oil pressure). The seal oil gas separators can be

designed to operate at the same pressure as the seal oil exiting the seal housing. The total cost of each

seal oil gas separator is estimated at $9,850, and with two separators per compressor (one for the seal

at each end of the shaft), the total cost per compressor is $19,700.

Seal Oil Recovered Gas Demister/Filter

After being recovered, the gas must pass through at least one high‐efficiency demister to remove

entrained seal oil before it can be sent to a fuel line. If the oil isn’t removed, the entrained oil may foul

burners and potentially clog fuel injectors. This demister can be designed to receive gas from multiple
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separators, thereby lowering the overall cost. However, the design characteristics of this vessel will vary

depending on the number separators connected to the vessel. The estimated cost for a single‐stage is

approximately $9,000. This cost will be used for both the single compressor and the compressor station

examples.

If the recovered gas is to be sent to a high pressure fuel system, such as to power the compressor, the

recovery system may need to include a second high‐efficiency filter. This is used to ensure that trace

amounts of seal oil do not foul these more sensitive fuel injectors. The estimated cost for the second

seal oil high‐efficiency filter is approximately $5,000.

Piping and Instrumentation

Piping modifications will be required in order to route the seal oil exiting the compressor seal to the new

separator then to the degassing tank.  Additional pipes and valves will be needed to transport the

recovered gas to the demisters and further to the end use site. Controls will also need to be installed to

regulate the pressure and flow of the recovered gas from each high pressure separator.  This can be

accomplished with a critical orifice on the gas outlet from each separator which restricts gas flow using

choke flow effects. The piping and instrumentation costs are included in the installation and capital

costs for each individual piece of equipment listed in Table 5‐1.

Estimated Savings

The savings from this system are realized by generating additional gas sales if gas is routed to the

compressor inlet, or by reduced costs if using recovered gas for site fuel. Based on measurement

studies, the average methane emissions from centrifugal compressor wet seal degassing are 63 scfm of

gas per compressor. Assuming 8,000 hours of operation per year, the total gas emissions per year would

be 30 million cubic feet (MMcf) per compressor. Existing systems recover 99 percent of the entrained

gas in the seal oil. Therefore, this analysis assumes that only 1 percent of the gas is vented. This means

that nearly 30 MMcf of gas can be recovered per centrifugal compressor and will either displace the

same volume in fuel gas or result in additional sales if routed to compressor suction. At $4 per thousand

cubic feet (Mcf), savings from reduced fuel gas consumption is estimated to be $120,000 per year per

centrifugal compressor, and a station with four centrifugal compressors could expect to avoid $480,000

per year in fuel gas costs.

Comparing Costs to Savings

The economics of implementing a wet seal degassing recovery system are shown in Table 5‐2 using a

five‐year cash flow table. This analysis considers capital costs and savings from avoided fuel gas costs.

The capital costs assume the operator installs both the demister for low pressure fuel gas and a high

efficiency filter for high pressure fuel gas. While the actual economics will be highly site‐specific, the

analysis here shows that the economics of installing a wet seal gas recovery system are so attractive that
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companies should consider implementing this technology at any and all facilities with at least one

centrifugal compressor with wet seals.

Table 5‐2 ‐ Wet Seal Degassing Recovery System Costs and Savings for One Compressor

Costs and Savings ($) Year 0 Year 1 Year 2 Year 3 Year 4 Year 5

Capital & installation costs ($33,700)

Annual natural gas savings

($4.00/Mcf) $120,000 $120,000 $120,000 $120,000 $120,000

Net Present Value = $380,000

Internal Rate of Return = 350%

Payback Period = 3 months

Table 5‐3 ‐ Wet Seal Degassing Recovery System Costs and Savings for Four Compressors at a Station

Costs and Savings ($) Year 0 Year 1 Year 2 Year 3 Year 4 Year 5

Capital & installation costs ($92,800)

Annual natural gas savings

($4.00/Mcf) $480,000 $480,000 $480,000 $480,000 $480,000

Net Present Value = $1,600,000

Internal Rate of Return = 520%

Payback Period = 2 months

With these assumptions, the wet seal gas recovery system would pay back in less than a year. The

economics are compelling, but it should be noted that the installation may require each compressor to

be briefly shutdown in order to tie the seal oil circulation piping into the new gas disengagement

vessels.  At new facilities requiring wet seal centrifugal compressors, installation can also integrate the

degassing recovery systems into the process design. Wet seal degassing recovery systems are highly

effective at capturing emissions from wet seal compressors and subsequently reducing fuel gas

purchases and/or increasing gas sales with a high rate of return.

5.4. Liquids Unloading

5.4.1. Background

For many gas wells, particularly older gas wells, accumulation of fluids in the well is a serious issue. If left

untreated, this accumulated fluid will slowly off the well to the point where it will no longer produce gas
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to the sales line. Because of this, the fluids that accumulate in these wells must be regularly removed or

otherwise dealt with, a process known as “liquids unloading.”

Operators of wells with liquids loading issues have several options to treat the well. The most basic

remedy is to simply open and vent the well to the atmosphere. By opening the well to atmospheric

pressure, which is substantially lower than the gas sales line pressure, the well will begin producing

again. As the well is producing to the atmosphere, the gas will carry up and remove some of the

accumulated liquids in the well tubing. After venting the well, which usually lasts at least several hours,

the well will again be able to produce gas to the sales line. However, studies have shown that simply

venting wells to the atmosphere only removes about 15% of the accumulated fluids in the well. This

results in the need to frequently vent the well, as well as diminished overall production from the well. Of

course it also results in significant methane emissions and lost gas revenue.

There are a variety of other options available to operators to remove liquids without venting or with

much reduced venting. These range from foaming agents that reduce the density and surface tension of

the liquid to pumping or “artificial lift” technologies that remove the liquid from the well tubing.  Several

of the most common unloading technologies are discussed below.

5.4.2. Plunger Lifts

A plunger lift is a type of artificial lift that harnesses the natural energy of a gas well to push a plunger

and the accumulated column of fluid in the well to the surface. The gas pressure buildup in the casing‐

tubing annulus is used to push the plunger up the well while the plunger acts as a piston between the

gas and the liquid, maximizing the liquid removal and minimizing venting. Ideally, the plunger discharges

to the sales line, in which case there is no venting of methane to the atmosphere. Over time, however,

the well may not have enough pressure to operate the plunger against the sales line pressure, in which

case it will vent to the atmosphere. However, this is still typically a 90% reduction compared to venting

the well without a plunger lift.

A plunger lift system consists of several parts beyond just

the plunger (Figure 5‐3). At the top of the well, the plunger

resides in a lubricator during normal gas well operation.

The lubricator ensures that the plunger will travel freely up

and down the well. At the bottom of the well is a bumper

spring and hold down component. The bumper spring acts

to catch and support the falling plunger before liquids

removal. The hold down component prevents the bumper

spring from travelling up the well with the plunger during

liquids removal. In addition to these mandatory

components, many operators choose to install automation

Figure 5‐3 ‐ Plunger Lift Schematic
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equipment that will monitor and automatic deploy the plunger lift when necessary.

Plunger lifts operate on a cycle, either determined manually by the operator or automatically by an

associated computer program. The pressures in the tubing and casing are monitored, and changes in

these values are used to determine when to begin the plunger lift cycle.

At the beginning of the cycle, the well is shut‐in to stop the flow of gas. As the well is being shut‐in, the

plunger falls from the lubricator to the bottom of the well with the liquid on top of the plunger. Pressure

in the casing then begins building up. When the casing pressure is high enough to lift the plunger and

the liquids to the surface, the sales line valve will open, again permitting the flow of gas from the well.

The pressurized gas in the casing will then push the plunger and fluid column to the surface. As the

plunger arrives at the top of the well, it is caught and is held in place in the lubricator. At this point, the

well will be producing at the maximum flow rate. As fluid accumulates in the well again, the casing and

tubing pressures will change. When those values hit their predetermined mark to trigger a plunger cycle,

the sales line valve will close and the cycle will begin again.

Initially, the wells were shut‐in manually by an operator. This required the operator to drive out to the

well site, shut‐in the well, wait for the plunger to cycle, and then open the well back to the sales line.

This method was then streamlined by controlling the plunger cycles with simple mechanical timers.

These timers ensured that the wells were plunged on a certain schedule, and eliminated the need for an

operator to drive out to the well. However, well conditions change over time. If the liquid level in the

gas well is allowed to get too high, the pressure in the well may not be enough to plunge the well to the

sales line. In this case, the plunger may get stuck part way up the well and the well will need to be

plunged to the atmosphere, resulting in methane emissions.  If the fluid is too low, the plunger may

come up too quickly and damage the wellhead.

A more recent development is the use of computers to automate plunger lift cycles. These computers

collect and analyze data to determine the optimal time to plunge the wells, ensuring that the well runs

as efficiently as possible. Actively tracking the well conditions can help to ensure that the well can be

plunged to the sales line instead of the atmosphere, which can lower the overall methane emissions

from the well. However, this technology generally only makes sense on wells that plunge frequently. If a

well is only cycling once or twice a year, the added cost of automation may not make economic sense

for the well.

5.4.2.1. Plunger lift costs

A typical plunger lift installation includes the downhole assembly, the lubricator, and the plunger itself,

as well as associated vales and connections. The installation costs can be higher if automation

equipment is installed as well. Table 5‐4 shows typical cost ranges reported to the Gas STAR program for

installing plunger lifts with and without automation, though current costs estimates are typically $7,500
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to $15,000 and companies contacted for this study cited even higher costs if well clean‐outs or over

treatments are required.  

Table 5‐4 ‐ Reported Capital and Operating Cost Ranges for Installing Plunger Lift Systems

Mitigation Option Capital Cost Annual O&M Comments

Plunger Lift System $2,500 to

$10,000 per

well

$1,000 to

$10,000 per well

Capital cost represents plunger lift equipment and

setup cost. O&M cost represents plunger lift

maintenance such as inspecting/replacing

lubricator and plunger.

Plunger Lifts

System with

“Smart"

Automation

> $10,000 per

well

$100 to $1,000

per well

The “Smart” Automation System can be installed

at a cost of less than $12,000 per well dependent

on the number of wells, current automation and

transmission systems in place, and the location.

The system requires additional field personnel

training and engineering time to realize its full

benefits.

Plunger lifts are designed to improve the production efficiency of older, liquids‐rich gas wells. However,

they can also prevent the wells from being vented to the atmosphere, as would have been done

previously to remove liquids. The use of plunger lifts can help to substantially reduce methane emissions

from wells by preventing unnecessary venting of the wells. However, operators must ensure that

plunger lift implementation is designed to minimize emissions as well as improve productivity.

For example, plunger lifts are generally used to plunge the liquids in the gas well to the sales line. This

requires that the pressures and flowrates in the well be closely monitored to ensure that sufficient

energy exists to bring the plunger up during its cycle. If the pressure is allowed to fall too low, the well

will need to be opened to the atmosphere to increase the pressure gradient and allow the plunger to

bring the liquids to the surface. Allowing this to occur will reduce the potential emission reductions.

Further, since the well has been cleared of liquids, the gas will be producing at or nears its maximum

rate. If the well remains open to the atmosphere after plunger, which is common, the increased gas flow

rate may negate or possibly even exceed emissions from venting a non‐plunger well to the atmosphere.

5.4.3. Additional Options for Removing or Remediating Liquids Problems

There are a variety of other options to address liquids unloading. The most common of these options

include foam‐lift systems, gas‐powered lifts systems, positive displacement systems, and velocity tubing

strings. These systems are generally not applicable to all wells, and often times have a very limited range

or lifetime of applicability.
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5.4.3.1. Foam‐Lift Systems

Foam‐lift systems work by using a soap or surfactant (the “foaming agent”) to alter the physical

properties of the fluid. The surface tension and the liquid density of the liquids in the well are changed

by the addition of the foaming agent, which then reduces the critical velocity needed lift the liquid from

the well. The main restriction with the use of a foam‐lift system is that the foaming agents only react

with water, meaning these systems are limited to wells in which most of the liquid phase is water rather

than a hydrocarbon liquid. The main use of foam‐lift systems is in the deliquification of wells with low

reservoir pressure that need to be continuously produced to high sales line pressures. The foam‐lift

systems can also find use when tubing restrictions prevent the use of plunger lifts in a well.27

5.4.3.2. Velocity Tubing

In a gas well, the velocity of the gas is the key factor in whether or not the gas can lift liquids out of the

well. Once the gas velocity falls below the necessary velocity to lift the liquids, the liquids will begin to

accumulate in the well, leading to lower production rates and ultimately shutting in the well. One option

to increase the gas velocity is to lower the cross sectional area of the gas well tubing. This works

because the velocity of a gas flowing through a section of pipe is inversely proportional to the cross

sectional area of the pipe. This cross sectional area reduction can be achieved in a gas well one of two

ways. Both of these ways involve inserting a smaller pipe, or “velocity tubing,” inside the production

tubing. The first option uses the velocity tubing to simply reduce the cross sectional area of the

production tubing by not allowing gas to flow up the space occupied by the inserted tubing string. This

method is shown in Figure 5‐4. The second option is to use the inserted velocity tubing as the new

production tubing. The method chosen will depend on how much the cross sectional area needs to be

reduced in order to achieve the appropriate gas velocity.

                                                            

27 Weatherford. ”Foam‐Lift Analysis.” http://www.clientdemos.net/weatherford_tus/lift_systems/foam‐lift_systems
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Figure 5‐4 ‐ Installation of Velocity Tubing Serving to Reduction the Cross Section Area of the Production Tubing

Note: A velocity tubing string is inserted into the well to decrease the annual area, thereby increasing the gas

velocity, allowing for liquids removal from the well.

The installation of a velocity tubing string is a relatively simple process, beginning with calculating the

proper tubing diameter needed to achieve the required gas velocity to lift the liquids out of the well. The

actual installation of the velocity tubing string requires a well workover rig to install the smaller

diameter tubing string in the well. Velocity tubing works best in low volume gas wells. Candidate wells

include marginal gas wells producing less than 60 Mfcd.28

5.4.3.3. Gas‐Powered Lift Systems

Gas lift systems are a type of artificial lift process that closely resembles the natural flow process of a gas

well. These systems work by sending high pressure gas into the casing of the well in order to lower the

hydrostatic pressure in the production tubing. With the hydrostatic pressure lowered, an increased

pressure differential is established between the reservoir and the wellhead, allowing the gas to flow

more freely and carry more liquid to the surface. The main requirement for gas lift systems is an

economically available supply of high pressure natural gas. This high pressure gas can come from either

nearby wells or a compression source. If a high pressure gas source is available, gas lift is typically the

preferred form of artificial lift.29

                                                            

28 U.S. EPA. “Options for Removing Accumulated Fluid and Improving Flow in Gas Wells.”

http://epa.gov/gasstar/documents/ll_options.pdf   29 Weatherford. “Gas Lift Systems.” http://www.weatherford.com/Products/Production/GasLift/
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5.4.3.4. Positive Displacement Systems

Positive displacement systems are generally used when a well depletes to the extent that downhole

pressures are insufficient to support any other type of artificial lift system. Positive displacement

systems include progressing cavity pumps, electric submersible pumps, and reciprocating rod lifts,

among others.  All of these technologies work by utilizing some sort of outside energy source, such as a

gas‐powered engine or electric motor, to lift the fluid to the surface. These systems are generally much

more expensive to install and operate than the other lift systems, but they are the only ones that can

deplete liquid‐producing gas wells to their lowest possible pressure.30

5.4.4. Liquids Issues in Horizontal Wells

The majority of oil and natural gas wells have been vertical wells. However, the past decade has seen a

rapid growth of horizontal wells, particularly for shale gas production. These newer, horizontal wells

have many benefits over traditional, vertical wells.

 Multiple wells can be drilled from a single well pad.

 Formerly inaccessible regions can be reached and produced.

 Increased productivity of wells by increasing contact with reservoir rock.

Most new production areas, including the Marcellus and Bakken formations, are being developed today

thanks in part to this horizontal drilling technology. While most of these wells are still relatively new,

eventually many of them are expected to face liquids loading problems as the well ages. This presents a

unique challenge to the industry, as most technologies designed to remedy liquids loading issues are for

vertical wells. This means that new technologies and techniques will need to be developed to overcome

the unique issues presented by these new horizontal wells.

Most horizontal wells have very long non‐vertical sections. These non‐vertical sections are the main

issue for these wells regarding liquids loading. Current technology, such as plunger lifts and foaming

agents, are designed to work in vertical wells only. Both rely on gravity to place objects, either the

plunger or the foaming agent, into the well. The non‐vertical section of a well presents a challenge

because gravity cannot assist in placing the object at the “bottom” of the well.

Further, many horizontal wells are not entirely horizontal. Figure 5‐5 shows some of the different

configurations that “horizontally” drilled wells can take. Further, many wells are often a combination of

the well types shown in Figure 5‐5.  For example, a multi‐lateral well may be drilled so that some legs

                                                            

30 Weatherford. “ESP and Positive‐Displacement Lift Analysis.”

http://www.clientdemos.net/weatherford_tus/lift_systems/positive‐displacement_systems
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are positioned toe up, while others are positioned toe down, and the legs will contain undulations as

well.

Figure 5‐5 ‐ Different Types of Horizontal Wells

Since wells are being directionally drilled, usually to contact as much of the reservoir rock as possible,

undulations in the horizontal leg are extremely common. These undulations present serious challenges

for overcoming potential liquids loading issues. Water and other liquids can accumulate in the low spots,

while gas blocks can possible occur in higher spots.

Another issue faced by horizontal wells is the issue of determining critical gas flow velocity. Companies

normally use this data in their determination on how to deal with liquids in a gas well. However, most

models and equations that are currently used were developed for vertical wells. Overall, there is a need

for improved understanding and models to determine the critical gas flow velocity in horizontal wells.

Currently, much work is being done to find adequate and economic solutions to liquids loading issues in

horizontal gas wells. A consortium formed by the Artificial Lift R&D Council and lead by the University of

Tulsa includes numerous artificial lift companies investigating different aspects of this issue. Their work

includes the investigation of multiphase flow behavior in horizontal gas wells, the investigation of

artificial unloading techniques in horizontal gas wells, and the development of guidelines and

recommended practices for unloading horizontal gas wells.31

                                                            

31 Artificial Lift R&D Council. “Artificial Lift Selection for Horizontal Wells.”

http://www.alrdc.org/recommendations/horizontalartificiallift/index.htm
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One of the major issues with removing liquids form horizontal wells is that the trajectory of the

horizontal portion of the well impacts how liquids load and how they can be removed. However, the

flow patterns of gas in these different trajectories are not currently well understood. This makes

choosing the appropriate technology to recover the gas difficult, since each technology has certain

limitations. Currently, the industry trend is to use the same or similar selection criteria that have already

been identified for vertical or near‐vertical wells.  In order to ensure maximum efficiency is achieved

from deliquefying horizontal wells, similar criteria must be developed for these wells.32

As an example, Muskegon Development, is using a technology called “Sequential Lift” in order to

deliquefy horizontal gas wells. Muskegon, which produces in the Michigan Antrim shale, was

experiencing liquids issues in the horizontal portion of their wells, creating high back pressures and

severely reducing the production rates. Before switching to sequential lift systems, Muskegon had been

using traditional gas lift in an attempt to remove liquids from their horizontal wells. However, the

traditional gas lift systems were proving to be highly ineffective. In 2010, Muskegon began installing the

sequential lift systems in their horizontal wells. This system places small pumps out to the end of the

horizontal sections of well, resulting in much more complete well deliquification when used with gas lift

systems. In fact, Muskegon stated that “the improved lift efficiency alone produced a reasonable

payback, even without taking into account any improved productivity.”33

Some companies have begun designing additional technologies to attempt to deal with liquids issues.

For example, Lufkin has designed a hydraulic submersible pump specifically for horizontal wells. This

pump’s design can accommodate dewatering at low volumes, and the specific targeted formations are

coal bed methane and shale gas plays. 34

                                                            

32 Tulsa University. “TU Horizontal Well Artificial Lift Projects – Justification.” Available online:

http://tuhwalp.ens.utulsa.edu/technical_proposal/justification.html 33 Fiberspar. “Enhancing Production and Improving Lift Efficiency in Low‐Pressure Wells with Liquid‐Loading Conditions.”

Available online: http://fiberspar.com/sites/default/files/cs01_mar11.pdf   34 Lufkin. “HSP 5000TM Hydraulic Submersible Pump.” http://www.lufkin.com/index.php/component/content/article/16‐

products‐a‐services/oilfield/100‐hydraulic‐submersible‐pump
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6. Conclusions  

The key conclusions of the study include:

 Emission Growth ‐ Methane emissions from oil and gas operations are projected to grow 4.5% from

2011 to 2018, including reductions from recent regulations (NSPS Subpart OOOO). All of the

projected net growth is from the oil sector, largely from flaring and venting of associated gas. Nearly

90% of the emissions in 2018 come from existing sources (sources in existence in 2011).  

 80/20 Rule for Sources ‐ 22 of the over 100 emission source categories account for over 80% of the

2018 emissions, primarily at existing facilities.

 Abatement Economics ‐ A 40% percent reduction in onshore methane emissions is projected to be

achievable with existing technologies and techniques at a net total cost of $0.66/Mcf of methane

reduced, or less than $0.01/Mcf of gas produced. The cost for some measures and segments of the

industry is more or less than the net total. The initial capital cost of the measures is estimated to be

approximately $2.2 billion with the majority of the costs in the oil and gas production segments.

 Abatement Opportunities – By volume, the largest opportunities target leak detection and repair of

fugitive emissions (“leaks”) at facilities and gas compressors, reduced venting of associated gas, and

replacement of high‐emitting pneumatic devices.  

 Abatement by Segment – The majority of the projected emissions are found in the oil and gas

producing segments and the gas transmission segment. These three segments account for almost

70% of the projected reductions.

 Co‐Benefits – Reducing methane emissions will also reduce conventional pollutants. The methane

reductions projected here would also result in a 44% reduction in volatile organic compounds

(VOCs) and hazardous air pollutants (HAPs) associated with these methane emissions.  

There are several caveats to the results:

 The 2011 EPA inventory is the best starting point for analysis, but it is based on many assumptions

and some older data sources. Although the inventory is improving with new data, it is designed to

be a planning and reporting document and is imperfect, especially at the detailed level, for a

granular analysis of this type.

 Emission mitigation cost and performance are highly site specific and variable. The values used here

are estimated average values.

 The analysis presents a reasonable estimate of potential cost and magnitude of reductions within a

range of uncertainty.
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Appendix A. Additional Sensitivities

This Appendix presents additional analytical results and sensitivities for the base case results. These

include:

 Alternative gas prices – Figures A‐1 and A‐2 show the MAC Curve for gas prices at $3/Mcf and

$5/Mcf. As expected, the lower gas price results in a higher reduction cost ($1.48/Mcf of methane

reduced) due to the reduced value of recovered gas. A higher gas price results in a lower reduction

cost (‐$0.15/Mcf of methane reduced) compared to the baseline value of $0.66/Mcf of methane

reduced at $4/Mcf. The change in gas price only affects those measures and segments that can

monetize the reductions.

 Alternative discount rate/cost of capital – Figure A‐3 shows the base case with a higher discount

rate of 15%. The discount rate increases the cost of capital‐intensive measures. The cost of

reduction is $1.01/Mcf of methane reduced at the higher discount rate.

 Results expressed as dollars per ton of CO2 equivalent – Figures A‐4 and A‐5 show the results on a

$/tonne of CO2e basis. The baseline measures result in a reduction of 79 MMtonnes of CO2e at a

cost of $1.38/tonne CO2e at a 100 year global warming potential (GWP) of 25. Using a 20 year GWP

of 72 increases the estimated reduction to 226 MMtonnes of CO2e at a cost of $0.48/tonne CO2e.  

 Results expressed as dollars per metric tonne of methane – Figure A‐6 shows the base case results

on a $/tonne of methane basis. The baseline measures result in a reduction of 3.1 MMtonnes of

methane at a cost of $35/tonne of methane.

 Results expressed as a percent of methane emissions from on‐shore gas operations – Figure A‐7

shows the base case results as a percent of gross methane withdrawals. Methane emissions from

onshore gas operations in 2018 are projected to be approximately 1.3% of gross methane

withdrawals. The reductions identified in this analysis would reduce the emissions to just less than

0.8% of gross withdrawals.   
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    Figure A‐1 ‐ Sector MAC Curve ‐ $3/Mcf Gas Price

Figure A‐2 ‐ Sector MAC Curve ‐ $5/Mcf Gas Price  
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Figure A‐3 ‐ Sector MAC Curve – 15% Discount Rate

Figure A‐4‐ Sector MAC Curve – $/tonne CO2e – 100 Year GWP = 25
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Figure A‐5‐ Sector MAC Curve – $/tonne CO2e – 20 Year GWP = 72

Figure A‐6‐ Sector MAC Curve ‐ $/tonne Methane Reduced
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Figure A‐7‐ “Percent Leakage” Analysis
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Appendix B. Development of the 2011 Emissions Baseline

B.1. Overview

The analysis of methane emission reduction potential takes as its starting point the methane portion of

the Natural Gas and Petroleum Systems section of EPA’s Inventory of U.S. Greenhouse Gas Emissions and

Sinks: 1990‐2011. This inventory represents the most robust, comprehensive data set of its kind.

However, because the EPA Inventory is intended as a planning document – not a standalone source for

granular economic analysis – ICF created an alternative 2011 Baseline based on the EPA Inventory

structure and other data sources. This was not a complete update of the 2011 EPA inventory, which was

beyond the scope of this project, but an update of any sections for which new or better data could be

readily identified.

While the Baseline applied changes and adjustments to the structure of the data and many source

categories, causing increases and decreases, the overall effect was an increase of just 2.4% (10 Bcf) in

the net estimated methane emissions from the oil and gas sectors compared to the 2011 EPA Inventory.

The estimated emissions from the natural gas sector were reduced by over 2% (10 Bcf) while the

emissions from the oil sector increased by nearly 26% (20 Bcf) compared to the 2011 EPA baseline (see

table below).   

B.2. Summary of Changes

The starting point for the 2011 Baseline was the U.S. EPA’s Inventory of U.S. Greenhouse Gas Emissions

and Sinks: 1990‐201135 published in April 2013, which estimates 436 billion cubic feet (Bcf) or 8.4 million

metric tonnes (MMTonnes) of methane emissions for the petroleum and natural gas sectors36. The

Natural Gas sector and the Petroleum sector are further divided in the inventory into the various

segments for the natural gas sector (Gas Production, Gathering and Boosting, Gas Processing, Gas

Transmission, Gas Storage, LNG Import/Export, and Distribution) and the petroleum sector (Oil

Production, Transportation, and Refining).

The Inventory breaks out methane emissions for approximately 200 sources, and calculates uncontrolled

emissions using activity factors (e.g., equipment counts) multiplied by emission factors (average

emissions from each source) to estimate the total emissions. The total uncontrolled emissions are offset

by emission reductions reported primarily from the EPA’s voluntary Natural Gas STAR Program, plus

additional reductions from other sources, such as state regulations.  

                                                            

35 U.S. EPA, “Inventory of U.S. Greenhouse Gas Emissions And Sinks: 1990‐2011”,

http://www.epa.gov/climatechange/ghgemissions/usinventoryreport.html 36 While the 2013 edition of the Inventory was the current version at the time the study was initiated, EPA has since released

the draft of the 2014 edition. However this study does not address that newer version of the Inventory.
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Summary of 2011 Emissions Baseline

Segment

2011 EPA Inventory ICF 2011 Baseline

Change (%) (Million

tonnes CH4) (Bcf CH4) (Milliontonnes CH4) (Bcf CH4)

Natural Gas

Gas Production            2.2               113                 2.0               103   ‐9%

Gathering and Boosting              0.5                 24                 0.8                 43   80%

Gas Processing              0.9                 48                 0.8                 44   ‐9%

Gas Transmission        1.7                 87                 1.4                 75   ‐14%

Gas Storage 0.3                 17               0.3                15   ‐11%

LNG 0.1                   5                 0.1                  6   22%

Gas Distribution        1.3                 69                 1.3                 69   0%

Petroleum

Oil Production 1.4 72 1.8 92   27%

Oil Transportation < 0.1 < 1 < 0.1 < 1   1%

Oil Refining < 0.1 1 < 0.1 1   0%

Total Net Gas Emissions 7.0 362 6.8 353   ‐2%

Total Net Oil Emissions 1.4 73 1.8 93   26%

Total Emissions 8.4 436 8.6 446   2.4%

During the development of 2011 Baseline, ICF focused on updating these factors for numerous sources.

The changes that were made, which are documented below, came from several publically available

references. The most common source of new information was the U.S. EPA’s mandatory Greenhouse

Gas Reporting Rule (GHGRP) subparts C (combustion from stationary sources) and W (methane

emissions from petroleum and natural gas systems). ICF also used information and data from the U.S.

Energy Information Administration (EIA), EPA’s 1996 GRI study of methane emissions37, the EPA Manual

                                                            

37“Methane Emissions from the Natural Gas Industry” http://epa.gov/gasstar/tools/related.html  
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of Emission Factors AP‐4238, various state energy and environmental departments, and the

EDF/University of Texas methane measurement study39.  Much of this information, in particular the data

from subpart W was not available at the time that the EPA Inventory was originally developed.

B.3. Natural Gas Inventory

The largest change to the structure of the Natural Gas segment in the 2011 Baseline was breaking out

the Gathering and Boosting segment. This is the segment between onshore Production and either Gas

Processing or Gas Transmission. This segment is included in the onshore Production segment of the EPA

Inventory based on the 1996 GRI measurement study rather than being fully broken out as a separate

segment. In this study, some sources were moved from Production to the Gathering and Boosting

segment in order to allow them to be analyzed separately for this segment and new emissions

estimates, for some sources underrepresented in the 2011 EPA inventory, were added. The major

source additions were new estimates of compressor and pneumatic device emissions. In addition,

emissions from condensate tanks were moved from the Production segment to the Gathering and

Boosting segment.

B.3.1. Gas Production

B.3.1.1. Natural Gas Well Counts

Up until the U.S. Inventory published in April 2013, natural gas well counts were obtained from the

World Oil magazine. The World Oil magazine provides the total well count in the U.S., and then

hydraulically fractured and non‐hydraulically fractured wells were split out in the Inventory using data

gathered from state energy agencies. In the EPA Inventory published in April 2013, the well counts were

obtained from DI DesktopTM, based on the HPDITM database. While the HPDITM database gives a much

more accurate ratio of hydraulically fractured wells to non‐hydraulically fractured wells, it does not

contain all of the operating wells in the U.S. (The World Oil magazine lists about 5% more wells than are

in HPDITM). Therefore, the well counts were updated by increasing the overall well count by 5%. This well

count also affected the count of associated well equipment, as detailed in section B.3.1.3.

B.3.1.2. Well Head Fugitives

Fugitives from well heads were separated by region (Eastern U.S. versus Western U.S.) in the EPA

Inventory. In the 2011 Baseline, this emissions source uses a new single national emission factor. The

emission factor was developed from the work done by the University of Texas for EDF on fugitive

emissions from well sites. From this study, any identifiable well head emissions (i.e., emissions from the

well itself, not the associated equipment) were grouped together and then divided by the well count at

                                                            

38 http://www.epa.gov/ttn/chief/ap42/index.html 39 Allen, David, et. al., “Measurements of Methane Emissions at Natural Gas Production Sites in the United States”.

10.1073/pnas.1304880110
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those sites to determine an overall per well emission factor. The updated factor was 97.6 standard cubic

feet per day (scf/day) of whole gas emissions, compared to the Eastern and Western factors of 9.0 and

46.2 scf/day of whole gas, respectively.40  This new factor was then applied to the updated well count

(see section B.3.1.1). These changes resulted in a 420% increase in emissions, to 14 Bcf.

B.3.1.3. Heaters, Separators, Dehydrators, and Meters/Piping (Well Fugitives)

The 1996 GRI study provides separate emission factors for the eastern and western U.S. for these

sources, with the eastern factors substantially lower than the western factors. These emission factors

were kept the same for the 2011 baseline year, but changed for the 2018 projection, as detailed in

section C.4.1. The big change to these sources was to update the activity factors in order to correspond

with new the well counts (in the EPA Inventory, the well counts drive the equipment counts for these

sources). This change resulted in a collective 4% increase in emissions for these sources to 15 Bcf.

B.3.1.4. Gas Well Completions

Gas well completions are broken out for hydraulically fractured wells and non‐hydraulically fractured

wells. The emissions from these two categories in the EPA Inventory were compared to the emissions

from subpart W and found to differ quite dramatically. The EPA Inventory uses whole gas emission

factors of 9,000,000 scf/completion for uncontrolled hydraulically fractured wells and 733

scf/completion for non‐hydraulically fractured wells. The emissions data from subpart W, from both the

2011 and 2012 reporting cycles, was used to develop new emission factors. These factors were derived

by aggregating the total emissions from the different completion types and then dividing by the count of

completions. These factors include emissions reductions during the completion process and so are not

directly comparable to the EPA factor for uncontrolled completions. This analysis derived methane

emission factors of 1,500,000 scf CH4/completion for hydraulically fractured wells and 70,000 scf

CH4/completion for non‐hydraulically fractured wells.  

Both the EPA Inventory and the 2011 Baseline apply Gas STAR, regulatory, and other reductions (in the

form of reduced emission completions (RECs) and “green” completions) to the uncontrolled emissions

from hydraulically fracture well completions. Because of this, the EPA emission factor for hydraulically

fractured well completions (9,000,000 scf whole gas/completion) was kept, but the application of the

various reductions brought the overall emissions down to the level suggested by the subpart W derived

emission factor, for a net level of emissions of 13 Bcf from hydraulically fractured well completions. For

non‐hydraulically fractured well completions, the subpart W derived emission factor was adopted.

The activity factors for both of these sources were updated using completions data from the most

recent API Quarterly Completions Report. These values are 8,480 hydraulically fractured well

                                                            

40 These values are listed in terms of methane in emissions in the EPA Inventory. They are 7.1 and 36.4 scf/day of methane,

respectively. They were converted to whole gas using the EPA volumetric methane content of 78.8%.
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completions and 4,592 non‐hydraulically fractured well completions for 2011, compared to the EPA

values of 8,077 hydraulically fractured well completions and 799 non‐hydraulically fractured well

completions. Using these updated factors, the emissions from hydraulically fractured well completions

were reduced by about 55% to 13 Bcf, and emissions from non‐hydraulically fractured well completions

increased to 0.3 Bcf.

B.3.1.5. Well Drilling

The number of wells drilled was updated to reflect the number of completions in 2011, as described in

section B.3.1.4. Each well completion was counted as one well drilled, and this decreased the count of

wells drilled from 14,807 in the EPA Inventory to 13,072 wells drilled in the 2011 Baseline. This resulted

in a net decrease in emissions from well drilling by 12% to 0.03 Bcf.

B.3.1.6. Well Testing

This source was not included in the published EPA Inventory, but it is included in subpart W of the

GHGRP. Therefore, emission and activity factors were developed from the 2011 and 2012 subpart W

data and were included in the 2011 Baseline. The subpart W derived emission factor is 95,000 scf/well

tested, and the reported number of wells tested in subpart W is 11,111 per year. It was assumed that

subpart W covers 85% of the reporters41, so the activity factor was increased to 13,072 wells tested per

year. The Well Testing methane emissions totaled over 1 Bcf.

B.3.1.7. Pneumatic Devices

Pneumatic devices in the published Inventory were listed as a single category and used a single emission

factor of 345 scf/day (126 Mcf/year). However, pneumatic devices are reported in subpart W in three

categories: low bleed, intermittent bleed, and high bleed devices. In order to break out the devices into

the respective categories, the emissions data reported to subpart W for 2011 and 2012 were analyzed.

From each device type’s emissions, the count of each device type was back calculated using the

prescribed emission factor in subpart W. This analysis gave a ratio of 10% high bleed, 50% intermittent

bleed, and 40% low bleed devices.

The “intermittent bleed” category covers a variety of different types of devices with different emission

characteristics and is not well‐characterized either in the subpart W data or other sources of emission

data. Some of these, as characterized in the subpart W emission factors, have a relatively high emission

factor, while others are much lower. For this reason, the intermittent devices were further segregated

into two categories: dump valves and non‐dump valve intermittent devices. The dump valves represent

devices that do not have a continuous bleed and generate emissions only when actuating, resulting in

far fewer emissions. These types of devices are generally found as level controllers in separators. In

order to obtain the number of dump valves in operation, the number of intermittent bleed devices was

                                                            

41 This assumption was derived during the development of subpart W and is applied thoughout this analysis.
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compared to the count of separators. Assuming that approximately 80% of separators have a lower‐

emitting intermittent bleed dump valve yielded an estimate that approximately 75% of the total

intermittent bleed devices were dump valves.

Additionally, the overall count of pneumatic devices was updated, to reflect the updated well counts, as

described in section B.3.1.1, and to better characterize the Gathering and Boosting sector. The count of

pneumatic devices is driven off of the well counts in the 2011 EPA Inventory, and the overall activity

factor driver is 0.94 pneumatic devices per well. This factor was compared to the result of a study

performed by API/ANGA42, which characterized the pneumatic devices in the Production and Gathering

and Boosting sectors. The activity factor driver developed in the study was 0.99 pneumatic devices per

well, which matched closely with the driver from the EPA Inventory. Therefore, no change was made

there. However, the study also found that there were an additional 8.6 pneumatic devices per

Gathering/Compressor Station. Since these devices were not accounted for in the EPA Inventory, this

factor was used to add in the devices associated with Gathering Stations, which are further described in

section B.3.2.3. This change resulted in an additional 23,000 pneumatic devices, which were subject to

the same split as described above and are included in the Gathering and Boosting Segment.  

Updated emission factors were obtained for the different pneumatic device types from an analysis of

subpart W data. Total emissions from each device type were divided by the device count (obtained as

described above) to obtain national emission factors for each type of pneumatic device. The emissions

factors were determined to be 320 Mcf/yr/device, 120 Mcf/yr/device, and 11 Mcf/yr/device for high

bleed, intermittent bleed, and low bleed devices, respectively. For intermittent bleed devices, it was

assumed that dump valves have approximately 80% fewer emissions than non‐dump valve intermittent

bleed devices based on discussions with industry stakeholders, and therefore were assigned an emission

factor of 20 Mcf/yr/device. The count of devices was updated as well in order to correspond with the

updated well count described in section B.3.1.1. Overall, these changes resulted in a 41% increase in

emissions from pneumatic devices to over 26 Bcf.

B.3.1.8. Chemical Injection (Pneumatic) Pumps

The count of chemical injection pumps was updated to reflect the updated well counts, as described in

section B.3.1.1. Further, in the EPA Inventory, there is a Gas STAR reduction associated with pneumatic

pumps. However, in the EPA Inventory, this is only applied to Kimray pumps and not chemical injection

pumps. In the 2011 Baseline, these reductions are also allocated, in proportion, to chemical injection

pumps. These reductions totaled just less than 2 Bcf of methane. These changes resulted in a net

increase of emissions by about 2% to over 3 Bcf.

                                                            

42 API and ANGA. “Characterizing Pivotal Sources of Methane Emissions from Natural Gas Production.” Found online at:

http://www.api.org/~/media/Files/News/2012/12‐October/API‐ANGA‐Survey‐Report.pdf
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B.3.1.9. Dehydrators and Kimray Pumps

Emissions from dehydrator vents and Kimray Pumps were compared to the emissions reported in

subpart W, and the subpart W emissions were shown to be much lower than the estimated emissions in

the EPA Inventory. However, it was determined that subpart W is underreporting emissions because

many dehydrators would fall into the Gathering and Boosting segment of the industry, which is not

covered by subpart W.  Therefore, the dehydrator emissions reported to subpart W were allocated to

the Gas Production segment, and the remaining emissions from the EPA Inventory were moved to the

new Gathering and Boosting segment. Overall, no change to the emission factor or activity factor

occurred. However, as described in section B.3.1.8, Gas STAR reductions for pneumatic pumps were

originally only allocated to Kimray pumps in the EPA Inventory, but were broken out to include chemical

injection pumps in the 2011 Baseline. Therefore, the total Gas STAR reductions allocated to Kimray

pumps decreased to just under 7 Bcf, while the net emissions from dehydrators and Kimray pumps

increased 22% to nearly 17 Bcf.

B.3.1.10.Condensate Tanks

Data reported to subpart W was used to update the emission factors for condensate tank venting. The

data pulled from subpart W was on a state basis and included average API gravity, separator pressure,

and separator temperature. This data was then used to run simulations through API’s E&P TankTM

software in order to develop new emission factors. The emission factors for each state were then

averaged into emission factors for each NEMS region, with the only missing region being the west coast,

which used a country‐wide average instead. The new emission factors, shown in the table below, were

then used to calculate updated emissions.

Condensate Tank Emission Factor Changes

Region

Emission Factor (scf/bbl)

EPA Inventory 2011 Baseline

Northeast 21.9 23.0

Gulf Coast 21.9 16.9

Midcontinent 302.8 15.0

Southwest 302.8 10.8

Rocky Mountain 21.9 39.0

West Coast 21.9 21.0

Alaska N/A 21.0

To stay consistent with the EPA Inventory methodology, it was assumed that 50% of the tanks had

control measures in place and that the measures were 80% effective. This resulted in a decrease in

condensate tank emissions by 80% to 2 Bcf. These emissions were moved to the Gathering and Boosting

segment.
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B.3.1.11.Dump Valve Venting

This source was not included in the published EPA Inventory, but it is included in subpart W of the

GHGRP. Therefore, emission and activity factors were developed from the 2011 subpart W data and

were included in the 2011 Baseline. The subpart W derived emission factor is 15,000 scf/year/leaking

valve, and the reported number of leaking dump valves to subpart W is 7,916. It was assumed that

subpart W covers 85% of the reporters, so the activity factor was increased to 9,313. The dump valve

venting methane emissions totaled over 0.1 Bcf.

B.3.1.12.Gas Well Workovers

Emissions from gas well workovers for both hydraulically fractured and non‐hydraulically fractured wells

were compared between the published EPA Inventory and the data reported to subpart W. The data

reported to subpart W suggested that emissions from hydraulically fractured well workovers is lower

than in the EPA inventory, while emissions from non‐hydraulically fractured well workovers are higher.

Therefore, the data from subpart W was used to update both the emission and activity factors. The new

emissions were calculated as 790,000 scf/workover for hydraulically fractured well workovers and

135,000 scf/workover for non‐hydraulically fractured well workovers. The number of workovers

reported to subpart W was 1,060 for hydraulically fractured wells and 11,663 for non‐hydraulically

fractured wells.  It was assumed that subpart W covers 85% of the reporters, so the activity factors were

increased to 1,247 and 13,721, respectively. For wells with hydraulic fracturing, emissions dropped

about 90% to 1 Bcf. For non‐hydraulically fractured wells, emissions increased to nearly 2 Bcf.

While determining the factors from hydraulically fractured gas wells in subpart W was straightforward,

the non‐hydraulically fractured gas well analysis was less clear. For non‐hydraulically fractured gas wells,

emissions from completions and workovers were lumped together, and the only way to separate them

out was to use the reported number of “Completion Venting Days” in subpart W. Therefore, only those

production sites that reported no completion venting days but still reported emissions were used to

determine the factors for gas well workovers without hydraulic fracturing.

B.3.1.13.Liquids Unloading (Gas Well Clean Ups)

Data reported to subpart W for 2011 and 2012 was used to develop new activity and emission factors

for wells with liquids unloading. From the subpart W data analysis, the number of wells venting with

plunger lifts was reported to be 37,643 and the number of wells venting without plunger lifts was

reported to be 26,451. It was assumed that subpart W covers 85% of reporters, so the number of

venting wells was increased to 44,286 and 31,113, respectively.

The emission factors were also updated using the data reported to subpart W for 2011 and 2012. The

total emissions for each venting well type (plunger lift versus non‐plunger lift) were divided by the total

number of reporting wells in order to obtain the new emission factors. From this analysis, the calculated

emission factors were 277,000 scf/venting well for wells with plunger lifts and 163,000 scf/venting well

for wells without plunger lifts.  
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Using these updated activity factors and emission factors results in a net increase of methane emissions

by 30% to 17 Bcf.

B.3.2. Gathering and Boosting

This sector was previously included as part of the Production sector, but has been broken out in this

analysis so that it could be separately analyzed and because it appeared to be underrepresented in the

published Inventory. This sector in the in the 2011 Baseline contains emissions from compressors (both

reciprocating and centrifugal), compressor stations, pneumatic devices, and pipelines. Some other

supporting equipment types were left in their respective sectors, as found in the EPA Inventory.

B.3.2.1. Compressors

The published EPA Inventory currently calculates the count of compressors in each NEMS region based

on the number of gas wells in that region. The vast majority (>99%) of these compressors are estimated

to be small compressors and emissions are calculated using an emission factor of 267 scf /day. A very

small number of compressors are estimated to be large compressors and use an emission factor

developed for transmission compressors of 15,205 scf /day. Both of these emission factors come from

the 1996 EPA/GRI study. Using the background data from this study, it was determined that the average

size of a transmission compressor in the GRI study was 1,600 horsepower.

In order to update the emission factors for this source, state energy agencies were contacted in an

attempt to obtain a list of permitted engines in the production sector of the petroleum and natural gas

industry. From the outreach, five states provided detailed engine counts. These states were Texas,

Colorado, Wyoming, Oklahoma, and Pennsylvania. The engines were sorted so that only production and

gathering compressors remained. The compressors were then split into small and large compressor

groups using a 1,600 hp threshold, as determined from analysis of the raw data from the 1996 EPA/GRI

study. The state data showed a much higher share of large compressor engines than assumed in the EPA

Inventory methodology. A weighted average emission factor, using the emission factors from the EPA

Inventory, was then developed from this data. The new emission factor for all gathering compressors

was calculated at 1,980 scf/day/compressor.

An additional update to the reciprocating compressors emission factor was applied in order to break out

emissions from compressor seals versus the other compressor fugitives. The U.S. Inventory uses a single

emission factor to cover all fugitive emissions from reciprocating compressors. However, the source

document for the emission factor (the 1996 GRI Report) breaks out the emissions from the separate

sources on a compressor, including blowdown lines, PRVs, open ended lines, compressor seals, and

miscellaneous. The factor for compressor seals was separated out from the other factors in order to

break emissions into two categories: “Reciprocating Compressors – Non‐Seals” (75%) and “Reciprocating

Compressors – Seals” (25%).

The state data was also used to develop new activity factors for reciprocating compressors. The

compressor count was then scaled up from these five states using the EPA Inventory ratio of
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compressors in these five states to the national count of compressors to obtain a new national

reciprocating compressor count of 15,687. Accounting for all of these changes, the net change in

emissions from reciprocating compressors was an increase of 166% to 11 Bcf.

Subpart W also reported the use of wet seal centrifugal compressors in the upstream sector. This data

was used to create a new emission category for wet seal centrifugal compressors. The number of

reported compressors was 162, and assuming that subpart W covers 85% of reporters, the activity factor

was set at 191. The subpart W emission factor, 12,000,000 scf/year/compressor, was also used in the

2011 Baseline. The emissions from this source were over 2 Bcf.

B.3.2.2. Compressor Exhaust (Gas Engines and Gas Turbines)

The exhaust from compressor engines and turbines contains some unburned methane. The activity

factor for these two emissions sources in the published Inventory is based on the total horsepower‐

hours of the equipment. However, the U.S. EIA publishes the amount of natural gas used as “Lease

Fuel,” which is fuel burned at natural gas production sites. This fuel volume was used as the new activity

factor. The analysis assumed 80% of the lease fuel was consumed in engines and turbines and the

breakdown between engines and turbines was determined to be 99% to 1%, respectively, using the

breakdown of compressors reported to subpart W for production.

The emissions factors were updated using emissions factors from the EPA’s manual of emission factors

(“AP‐42”). Since AP‐42 lists 3 separate emission factors for engines (two stroke lean‐burn, four stroke

lean‐burn, and four stroke rich‐burn), a combined emission factor was developed based on the data

obtained from the state energy agencies, as described in section B.3.2.1. Four of the states either listed

the engine type or provided enough data to determine the engine type for the compressors listed. This

data set, which contained nearly 10,500 compressors/engines across all sectors of the industry, was

used to determine the breakout of engine types: 10% two stroke lean‐burn, 34% four stroke lean‐burn,

and 56% four stroke rich‐burn. These ratios were used to give an overall emission factor for engines of

332 kg CH4 per MMscf gas burned (17,280 scf CH4/MMscf gas burned). The emission factor for turbines,

4.0 kg CH4 per MMscf gas burned (208 scf CH4/MMscf gas burned), was listed directly in AP‐42 and used

as‐is. These modifications resulted in a 7% decrease in emissions to just over 10 Bcf.

B.3.2.3. Gathering and Boosting Stations

Formally called “Large Compressor Stations” in the EPA Inventory, this count of stations was determined

from the number of large compressors in the Inventory, which as stated in section B.3.2.1 was very

small. The updated gathering station count was determined using an assumption that each processing

plant has 3 gathering stations that feed into it. This resulted in an increase of stations to over 2,700. The

emissions also increased substantially, rising to over 8 Bcf.

B.3.2.4. Dehydrators and Kimray Pumps

See section B.3.1.9 for explanation.
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B.3.2.5. Pipeline Leaks, Pipeline Blowdowns, Compressor Starts, and Compressor Blowdowns

These emissions were moved from Production to Gathering and Boosting to better represent the

breakout of emissions in the industry. Also, the number of compressors was updated for compressor

starts and blowdowns in order to match the number of compressors from the state data analysis, as

described in section B.3.2.1. The emission factors for these sources did not change, but the overall

methane emissions decreased by 2% to 9 Bcf.

B.3.3. Gas Processing

B.3.3.1. Gas Plant Fugitives

The gas plant count of 585 gas processing plants in the published Inventory comes from the Oil and Gas

Journal. This source lists only plants that contain fractionation equipment. However, there are large gas

treatment plants that do not contain fractionation equipment and are covered by subpart W. The EIA

also maintains a list of gas processing facilities. Therefore, the count of plants was compared between

these three sources to find the unique values, and it was determined that there are 909 gas processing

and treatment facilities in the U.S. This resulted in a 55% increase in emissions estimated for this source

category to nearly 3 Bcf.

B.3.3.2. Reciprocating Compressors

An update to the reciprocating compressor emission factor was made in order to break out emissions

from compressor seals versus the other compressor fugitives. This change is described in section B.3.2.1.

B.3.3.3. Gas Engine and Turbine Exhaust

The activity factor for these two emissions sources in the published Inventory is based on the total

horsepower‐hours of the equipment. However, the U.S. EIA publishes the amount of natural gas used as

“Plant Fuel,” which is fuel burned in natural gas processing plants. This fuel volume was used as the new

activity factor with an assumed 80% of the fuel being consumed in engines and turbines in a typical

processing plant. Further, the breakdown between engines and turbines was determined to be 46% to

54%, respectively, using the current horsepower‐hour ratios in the published Inventory.

The emissions factors were also updated, as described in section B.3.2.2.  In this case the emissions were

reduced by 74% for gas engines and 87% for turbines compared to the published inventory.

B.3.3.4. Pneumatic Devices

For processing plants, pneumatic devices are not broken out by bleed rate, as neither the EPA Inventory

nor subpart W has this information. Instead, the activity factor for pneumatic devices in processing is

the number of processing/gas treatment plants. This was updated to the 909 plants, as described in

section B.3.3.1. This resulted in an increase in emissions of 55% to nearly 0.2 Bcf. (Most processing

plants are believed to use instrument air instead of gas‐driven pneumatics.)
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B.3.3.5. Blowdowns/Venting

The activity factor for blowdowns/venting in processing is the number of processing plants. This was

updated, as described in section B.3.3.1. However, the EPA Inventory also details Gas STAR reductions

from this source. Overall, the updated net methane emissions increased 190% to 2 Bcf.

B.3.4. Gas Transmission

B.3.4.1. Pipeline Leaks

The total number and breakout of transmission pipeline miles in the U.S. was updated using data from

the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration

(PHMSA). The PHMSA data showed a lower value for transmission pipeline miles from 304,606 in the

EPA Inventory to 298,750 in the 2011 Baseline. The breakout was also used to assign the pipeline miles

to the respective regions.  This reduction in pipeline miles caused a reduction in emissions of 2%, to 0.2

Bcf. The pipeline miles are used to drive the number of compressors and compressor stations in the

transmission segment. These values were updated accordingly.

B.3.4.2. Transmission Compressor Stations

The number of compressor stations is driven off of the pipeline miles in the U.S. Inventory, so the

change in pipelines miles, as detailed in section B.3.4.1, caused the number of reciprocating

compressors to change from 1,808 to 1,768, resulting in an emissions decrease of just over 2%.

B.3.4.3. Reciprocating Compressors

Reciprocating compressor count is driven off of the pipeline miles in the U.S. Inventory, so the change in

pipelines miles caused the number of reciprocating compressors to change from 7,270 to 7,111,

resulting in an emissions decrease of over 2%. Further, an update to the reciprocating compressor

emission factor was made in order to break out emissions from compressor seals versus the other

compressor fugitives. This change is described in section B.3.2.1.

B.3.4.4. Centrifugal Compressors

Centrifugal compressor count is driven off of the pipeline miles in the U.S. Inventory, so the change in

pipelines miles caused the number of reciprocating compressors to change from 654 to 648, resulting in

an emissions decrease of over 2%.

B.3.4.5. Engine and Turbine Exhaust

The activity factor for these two emissions sources in the published Inventory is based on the total

horsepower‐hours of the equipment. However, the U.S. EIA publishes the amount of natural gas used as

“Pipeline Fuel,” which is fuel burned in natural gas transmission pipelines and at storage facilities. This

fuel volume was used as the new activity factor. The breakdown between transmission and storage was

done using the current horsepower‐hours listed in the published Inventory, which gave 90% to

transmission and 10% to storage. These horsepower‐hours ratios were also used to determine the

amount of fuel sent to engines versus turbines. For transmission, the fuel breakdown between engines
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and turbines was determined to be 81% to 19%, respectively. For storage, the fuel breakdown between

engines and turbines was determined to be 74% to 26%, respectively. The emissions factors were also

updated, as described in section B.3.2.2.  In this case the emissions decreased by 26% for gas engines

and decreased 63% for turbines.

B.3.4.6. Pneumatic Devices

Pneumatic devices were broken out the same as described in section B.3.1.7. This analysis led to a

breakdown of 15% high bleed, 75% intermittent bleed, and 10% low bleed in the transmission segment.

Updated emission factors were also obtained from subpart W data analysis and were determined to be

155 Mcf/yr/device, 20 Mcf/yr/device, and 12 Mcf/yr/device, respectively. This breakout resulted in a

74% decrease in emissions to just under 3 Bcf.

B.3.4.7. Dump Valve Leakage

This source was not included in the published EPA Inventory, but it is included in subpart W of the

GHGRP. Therefore, emission and activity factors were developed from the 2011 subpart W data and

were included in the 2011 Baseline. The subpart W derived emission factor is 950,000 scf/year/leaking

dump valve, and the reported number of leaking dump valves to subpart W is 318. It was assumed that

subpart W covers 85% of the reporters, so the activity factor was increased to 374. The dump valve

leakage methane emissions totaled over 0.3 Bcf.

B.3.4.8. Pipeline Venting

The activity factor for pipeline venting was updated, as described in section B.3.4.1. This resulted in a

decrease in emissions of 3%.

B.3.4.9. Transmission Station Venting

The activity factor for transmission station venting was updated, as described in section B.3.4.1. This

resulted in a decrease in emissions of 2%.

B.3.5. Gas Storage

B.3.5.1. Reciprocating Compressors

An update to the reciprocating compressor emission factor was made in order to break out emissions

from compressor seals versus the other compressor fugitives. This change is described in section B.3.2.1.

B.3.5.2. Pneumatic Devices

Pneumatic devices were broken out the same as described in section B.3.1.7. This analysis led to a

breakdown of 40% high bleed, 50% intermittent bleed, and 10% low bleed in the transmission sector.

Updated emission factors were also obtained from subpart W data analysis and were determined to be

155 Mcf/yr/device, 20 Mcf/yr/device, and 12 Mcf/yr/device, respectively. This breakout resulted in a

55% decrease in emissions to just over 1 Bcf of methane.
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B.3.5.3. Engine and Turbine Exhaust

The activity factor for these two emissions sources was updated, as described in section B.3.4.5. The

emissions factors were also updated, as described in section B.3.2.2.  In this case the emissions

decreased by 20% for gas engines and decreased 73% for turbines.

B.3.6. Liquefied Natural Gas (LNG)

B.3.6.1. Import/Export Terminals

LNG import/export terminals were increased from 8 in the EPA Inventory to 12 in the 2011 Baseline

from an analysis of operating terminals listed in the Federal Energy Regulatory Commission’s (FERC)

website. Part of this increase has to do with the fact that the EPA Inventory discounts the total number

of terminals by 30%, resulting in a reduced activity factor. This reduction was taken out of the 2011

Baseline. This increase in terminals increased station fugitives and station venting by 56% to nearly 0.2

Bcf.

B.3.6.2. Storage Stations

No changes were made to the count of storage stations.

B.3.6.3. Reciprocating Compressors (Import/Export and Storage)

For Import/Export Terminals, the count of reciprocating compressors was updated to reflect the new

station count using activity factor drivers from the EPA Inventory. For Storage Stations, the EPA

Inventory differentiates between “Complete Storage Faculties” and “Satellite Storage Faculties” in order

to calculate the number of compressors. However, there was insufficient data to maintain this

distinction in the 2011 Baseline, which caused the count of compressors to increase from 270 to 368. An

update to the reciprocating compressor emission factor was made in order to break out emissions from

compressor seals versus the other compressor fugitives. This change is described in section B.3.2.1.

These changes caused an increase in compressor emissions for Import/Export Terminals by 9% and for

Storage Stations by 36%.

B.3.6.4. Centrifugal Compressors (Import/Export and Storage)

Compressor counts were changed, as described in section B.3.6.3. The updated counts were 7

centrifugal compressors at Import/Export Terminals (up from 6.6) and 88 centrifugal compressors at

Storage Stations (up from 64). The change in emissions was an increase of 9% and 36%, respectively.

B.3.6.5. Compressor and Engine Exhaust (Import/Export)

The activity factors were changed to reflect the reported LNG throughput at the Import/Export

Terminals, as determined by ICF’s internal analysis of EIA data. The throughput of 349 Bcf (as reported

to EIA), compared to the throughput of 431 Bcf in the EPA Inventory, led to a 19% decrease in the

emissions.
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B.3.7. Gas Distribution

No changes were made to this segment of the U.S. Inventory.

B.4. Petroleum Inventory

The net change to the Petroleum segment of the U.S. Inventory was an increase of 26% compared to the

EPA Inventory value. The biggest categories contributing to this increase were the inclusion of stranded

gas venting from oil wells and updated estimates of associated gas flaring estimates. The specific

changes are described in the following sections.

B.4.1. Oil Production

B.4.1.1. Oil Tank Venting

This section was not changed.

B.4.1.2. Oil Tank Dump Valve Venting

This source was not included in the published EPA Inventory, but it is included in subpart W of the

GHGRP. Therefore, emission and activity factors were developed from the 2011 subpart W data and

were included in the 2011 Baseline. The subpart W derived emission factor is 17,000 scf/year/leaking

dump valve and the reported number of leaking dump valves to subpart W is 3,044. It was assumed that

subpart W covers 85% of the reporters, so the activity factor was increased to 3,581. The dump valve

venting methane emissions totaled nearly 0.1 Bcf.

B.4.1.3. Pneumatic Devices

Pneumatic devices in the EPA Inventory were broken out into two categories, low bleed and high bleed,

with two emission factors, 52 scf/day (19 Mcf/yr) and 330 scf/day (210 Mcf/yr), respectively. For the

2011 Baseline, pneumatic devices were broken out the same as described in section B.3.1.7. The overall

count of devices was kept the same as in the EPA Inventory. The net effect of these changes is an

increase in emissions of 8% to over 24 Bcf.

B.4.1.4. Chemical Injection (Pneumatic) Pumps

The count of devices in the published Inventory was compared to the count obtained from subpart W,

and was shown to be underestimated (30,600 devices in subpart W vs. 28,000 in the Inventory).

Therefore, the updated count from subpart W was used and results in an increase of emissions by about

10%. However, Gas STAR reductions for gas powered pumps were not allocated to the chemical

injection pumps in the U.S. Inventory. This was corrected by subtracting a portion of the Gas STAR

reductions (determined by a weighted ratio). This resulted in a net decrease in emissions by 30% to just

less than 2 Bcf.

B.4.1.5. Oil Well Completions

Oil well completions were not broken out for hydraulically fractured wells and non‐hydraulically

fractured wells in the published Inventory, and used a single emission factor of 733 scf/completion.
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However, these two categories were broken out in subpart W, so this change was made to the 2011

Baseline. The data reported to subpart W was used to develop new emission factors, which were

230,000 scf/completion for hydraulically fractured oil wells and 220 scf/completion for non‐hydraulically

fractured oil wells.

The activity factors were updated using completions data from the most recent API Quarterly

Completions Report. These values are 15,382 hydraulically fractured well completions and 10,684 non‐

hydraulically fractured well completions for 2011. This compares to the single EPA value of 19,468 well

completions. Using the updated completion counts and emission factors, the emissions from

hydraulically fractured well completions were 5 Bcf, and emissions from non‐hydraulically fractured well

completions were less than 0.01 Bcf.  

B.4.1.6. Oil Well Workovers

Oil well workovers were not broken out for hydraulically fractured wells and non‐hydraulically fractured

wells in the published Inventory, and used a single emission factor of 96 scf/workover. However, these

two categories were broken out in subpart W, so this change was made to the 2011 Baseline. The data

reported to subpart W was used to develop new emission and activity factors. The new emission factors

were found to be 440,000 scf/workover for hydraulically fractured oil wells and 310 scf/workover for

non‐hydraulically fractured oil wells. The activity factors were 143 hydraulically fractured oil well

workovers and 40,200 non‐hydraulically fractured oil well workovers.

While determining the factors from hydraulically fractured oil wells in subpart W was straightforward,

the non‐hydraulically fractured oil well analysis was less clear. For non‐hydraulically fractured oil wells,

emissions from completions and workovers were lumped together, and the only way to separate them

out was to use the reported number of “Completion Venting Days” in subpart W. Therefore, only those

production sites that reported no completion venting days but still reported emissions were used to

determine the factors for oil well workovers without hydraulic fracturing.  

The net change to emissions was an increase to 0.04 Bcf.

B.4.1.7. Stranded Gas Venting from Oil Wells

This source was not included in the published EPA Inventory, but it is included in subpart W of the

GHGRP. Therefore, emission and activity factors were developed from the 2011 and 2012 subpart W

data and were included in the 2011 Baseline. The subpart W derived emission factor is 570,000

scf/yr/venting well, and the reported number of venting wells was 9,722. The Subpart W development

estimated that it would cover 85% of the sector, so the activity factor was increased to 11,438. This

category accounts for nearly 7 Bcf of emissions.

B.4.1.8. Oil Wellheads

The emission factors in the published Inventory were updated to the emission factors published in

subpart W. The well count was also updated to reflect the count in the World Oil magazine, as was done
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with the gas well count. Well types were broken out using an internal data set which broke out well type

by basin. This resulted in a net increase in emissions between light crude and heavy crude wellheads of

66%.

B.4.1.9. Separators

The emission factors in the published Inventory were updated to the emission factors published in

subpart W. This resulted in a net decrease in emissions between light crude and heavy crude separators

of 44%.

B.4.1.10.Heater/Treaters

The emission factor in the published Inventory was updated to the emission factor published in subpart

W. This resulted in a decrease in emissions of 43%

B.4.1.11.Headers

The emission factors in the published Inventory were updated to the emission factors published in

subpart W. This resulted in a net decrease in emissions between light crude and heavy crude headers of

46%.

B.4.1.12.Well Drilling

The number of oil wells drilled was updated to reflect the number of completions in 2011, as described

in section B.4.1.5. Each oil well completion was counted as one well drilled, and this increased the count

of wells drilled from 21,899 in the EPA Inventory to 26,066 wells drilled in the 2011 Baseline. This

resulted in a net increase in emissions from well drilling by 19% to 0.06 Bcf.

B.4.1.13.Flaring

The EPA bases its flaring estimate on company data reported to states and then to the EIA. In the 2011

Baseline, flaring was based on the values reported by the World Bank’s Global Gas Flaring Reduction

(GGFR)43 program. It was assumed that all of the estimated flaring was from associated gas. The GGFR

estimated that 7.1 billion cubic meters of gas was flared in the U.S. in 2011. It was then assumed that

the flares were 98% efficient, resulting in methane emissions of 5 Bcf. This is a large increase over the

value in the published Inventory (0.01 Bcf).

B.4.2. Oil Transportation

No changes were made to this segment of the U.S. Inventory.

B.4.3. Oil Refining

No changes were made to this segment of the U.S. Inventory.

                                                            

43 Available online at http://go.worldbank.org/G2OAW2DKZ0  
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Appendix C. Emission Projection to 2018

C.1. Summary

The 2018 forecast of U.S. natural gas and petroleum systems methane emissions starts with the 2011

Baseline described in Appendix B.  ICF based the emissions forecast on several sources to drive

emissions through the time horizon. The primary source was the U.S. EIA’s 2014 Annual Energy Outlook

(AEO) Early Release. ICF also relied upon EIA’s 2013 AEO, the API Quarterly Well Completion Report, and

an INGAA Foundation study44 which forecast requirements for selected infrastructure and equipment

for the natural gas and petroleum industry.  In addition, expected emission reductions as a result of

NSPS subpart OOOO were incorporated into the forecast.  The result is an estimated 9.5 million metric

tonnes (491 Bcf) of methane emitted from all sectors of the oil and gas industry in 2018 before

application of NSPS reductions, an increase of 12%. Inclusion of NSPS reductions reduces the emissions

to 9.0 million metric tonnes (466 Bcf), an increase of 4.5% from 2011, with all of the net increase coming

from the oil sector.

C.2. Natural Gas Inventory Activity Factors

C.2.1. EIA 2014 Annual Energy Outlook Early Release

ICF used EIA’s 2014 AEO Early Release “Lower 48 Natural Gas Production and Supply Prices by Supply

Region” forecast out to 2018, broken out into the eight AEO regions as shown in Figure 1, to drive the

growth for several of the sources in the natural gas sector.  The “Lower 48 Natural Gas Production and

Supply Prices by Supply Region” forecasts natural gas production, which was ultimately used as the

driver for each region for future emissions in 2018, per Equation 1.

ܨܣ௡௢௜௚௘௥ିଶ଴ଵଵ ൈ

ீ௔௦௉ೝ೐೒೔೚೙	ష	మబభఴ

ீ௔௦௉ೝ೐೒೔೚೙ష	మబభభ

ൌ ܨܣ௡௢௜௚௘௥ି	ଶ଴ଵ଼     Equation 1

Where:

AFregion‐2011 = regional activity factor for the 2011 inventory

GasPregion – 2018 = regional gas production projected in EIA’s 2014 AEO for 2018

GasPregion – 2011 = regional gas production in EIA’s 2014 AEO for 2011

AFregion – 2018 = regional activity factor for 2018 inventory projection

The activity factors for the following sources were driven using this method:

                                                            

44 North American Midstream Infrastructure Through 2035 – A Secure Energy Future, Prepared for the INGAA Foundation, ICF

International, 2011.
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 Gas Production and Gathering and Boosting

 Dehydrators

 Kimray pumps

 Condensate tanks  

 Compressor exhaust  

 Gas Processing

 AGRs

 Dehydrators

 Kimray pumps

 Gas Storage  

 Pneumatics

Map of EIA Regions

Source:  EIA AEO 2013

C.2.2. EIA 2013 Annual Energy Outlook

ICF used the EIA’s 2013 Annual Energy Outlook in addition to the 2014 Early Release for “Natural Gas

Consumption by End‐Use Sector and Census Division” since this data was not part of the 2014 Early
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Release. The Residential and Commercial gas consumption forecast was used from this data set as the

driver for many activity factors, per Equation 2.

ܨܣ௡௢௜௚௘௥ିଶ଴ଵଵ ൈ

ீ௔௦஼ೝ೐೒೔೚೙	ష	మబభఴ

ீ௔௦஼ೝ೐೒೔೚೙ష	మబభభ

ൌ ܨܣ௡௢௜௚௘௥ି	ଶ଴ଵ଼     Equation 2

Where:

AFregion‐2011 = regional activity factor for the 2011 inventory

GasCregion – 2018 = regional gas consumption projected in EIA’s 2013 AEO for 2018

GasCregion – 2011 = regional gas consumption in EIA’s 2013 AEO for 2011

AFregion – 2018 = regional activity factor for 2018 inventory projection

The activity factors driven by this forecast include all of the activity factors in Gas Distribution and Gas

Storage, except for those listed in section C.2.1. In the Gas Storage segment, it was assumed that even if

the gas consumption dropped in a region that the number of storage stations and associated equipment

did not drop. Further, Cast Iron Mains and Unprotected Steel Mains and Services in the Gas Distribution

segment were not driven by this forecast, as no further cast iron or unprotected steel equipment is

being installed in the U.S. Instead, it was assumed that 3% of the remaining cast iron and unprotected

steel equipment is replaced with protected steel and plastic equipment, respectively, each year based

on historical replacement reported to PHMSA.

C.2.3. API’s Quarterly Well Completions Report

ICF used API’s Quarterly Well Completions Report as the source to drive a majority of the emission

sources in the Gas Production segment. The analysis assumed that well completions will continue

through 2018 at the 2012 rate and used this summation of new well completions to drive well‐related

activity factors. In addition to new well completion, shut‐in and abandoned wells were also accounted

for in the well count forecast. To estimate the number of wells shut‐in per year, ICF compared the

growth rate of gas wells to the growth of gas production in each region. A shut‐in percentage, between

0.1% and 5%, was then assigned to each region in order to align the well count growth with the gas

production growth in that region. The regional percentages are listed below.

Gas Well Retirement Rate

Region Gas Well

Retirement Rate

Northeast 0.1%

Gulf Coast 1.0%

Midcontinent 2.0%

Southwest 2.0%

Rocky Mountain 1.0%
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Region Gas Well

Retirement Rate

West Coast 3.0%

Alaska 5.0%

Once the updated well counts were set for each region, a ratio of wells in 2018 to wells in 2011 was

used to drive the activity for most the emissions sources in the Gas Production segment. In addition to

using the ratio of wells, several emission sources in the Gas Production segment had their own activity

factor drivers from the EPA Inventory.  These activity factor drivers were multiplied by the 2018 well

counts to obtain new activity levels for 2018. These sources and their activity factor drivers are listed

below for each of the regions in the Inventory.

Activity Factory Drivers for Select Sources by Region

Source NE GC MC SW RM WC AK Units

Heaters 0.41 0.22 0.41 0.27 0.46 1.0 1.0 Per well

Separators 0.71 0.66 0.44 0.56 0.50 0.73 0.73 Per well

Dehydrators 0.14 0.14 0.14 0.14 0.14 0.14 0.14 Per well

Meters/Piping –  

Gas wells 1.15 1.15 1.15 1.15 1.15 1.15 1.15 Per well

Meters/Piping –  

Associated Wells 0.05 0.05 0.05 0.05 0.05 0.05 0.05

Per

assoc.

well

High Bleed

Pneumatic Devices 0.05 0.07 0.16 0.13 0.15 0.10 0.10 Per well

Intermittent Bleed

Pneumatic Devices 0.06 0.09 0.19 0.17 0.18 0.13 0.13 Per well

Intermittent Bleed

Pneumatic Devices –  

Dump Valves

0.18 0.26 0.58 0.50 0.55 0.38 0.38 Per well

Low Bleed Pneumatic

Devices 0.19 0.28 0.62 0.53 0.59 0.40 0.40 Per well

Chemical Injection

Pumps 0.14 0.03 0.14 0.06 0.18 0.68 0.68 Per well

Mishaps 0.25 0.25 0.25 0.25 0.25 0.25 0.25

Per

mile of

pipeline

†‐ Activity factor drivers also account for pneumatics from Gathering and Boosting Stations.

The only exceptions to the two methodologies described above for the Gas Production segment include

the gas well completion values for 2018, which used the 2012 gas well completion values directly from

the API Quarterly Well Completions Report, and the high bleed pneumatics. High bleed pneumatics are
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phased out in most segments due to NSPS subpart OOOO regulations but the forecast assumes that no

new high bleed pneumatics are installed in any segment.  

C.2.4. INGAA Foundation Midstream Study45

ICF used the INGAA Foundation study for the Gathering and Boosting and Gas Processing segments. The

INGAA study provided yearly forecast of incremental gathering pipeline miles, gas processing plants, and

processing compressor count, which was combined with the existing activity data from 2011, per

Equation 3.   

ܨܣ௡௢௜௚௘௥ିଶ଴ଵଵ ൅ ܨܫ௡௢௜௚௘௥ିଶ଴ଵ଼ ൌ ܨܣ௡௢௜௚௘௥ି	ଶ଴ଵ଼    Equation 3

Where:

AFregion – 2011 = regional activity factor for the 2011 Inventory

IFregion – 2018 =regional, cumulative INGAA forecast of equipment counts out to 2018

AFregion – 2018 = regional activity factor for 2018 inventory projection

For the Gathering and Boosting segment, the activity factors all of the emission sources were then

driven off of a ratio of pipeline miles in 2018 to pipeline miles in 2011 to obtain the 2018 activity levels,

except for those sources listed in section C.2.1.  

For the Gas Processing segment, pneumatic devices and blowdowns/venting were driven directly off of

the gas processing plant count. The other sources were all driven off of a ratio between the compressor

count in 2018 and the compressor count in 2011, except for those sources listed in section C.2.1.

C.2.5. Gas Transmission

Growth for the Gas Transmission segment was not driven off of a forecast, but rather off of an analysis

of past pipeline infrastructure changes. The EPA Inventory contains data on the length of transmission

pipeline miles back to 1990. The data from 1990 to 2011 was analyzed to develop a pipeline expansion

trend. This incremental value was then used to drive the pipeline miles forward to 2018. All of the other

sources, except those listed in section C.2.1, were then driven off of a ratio of pipeline miles in 2018 to

the pipeline miles in 2011.  

C.2.6. LNG

LNG Import/Export terminals were forecasted off of FERC data and an internal analysis of potential

import/export terminals. From this analysis, it is assumed that one new export terminal will come online

on the Gulf Coast by 2018. (Several other facilities will be converted from import to export terminals.)

                                                            

45 North American Midstream Infrastructure Through 2035 – A Secure Energy Future, Prepared for the INGAA Foundation, ICF

International, 2011.
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All of the other emission sources are either driven off of ratios between the 2018 and 2011 terminal

counts or EPA activity drivers, as described in sections B.3.6.2, B.3.6.3, B.3.6.4, and B.3.6.5.

C.3. Petroleum Inventory Activity Factors

C.3.1. EIA 2014 Annual Energy Outlook Early Release

ICF used EIA’s 2014 AEO Early Release “Petroleum and Other Liquids Supply and Disposition” and “Lower

48 Crude Oil Production and Wellhead Prices by Supply Region” forecasts out to 2018, broken out into

the same eight AEO regions as shown above for natural gas, to drive the activity for many of the sources

in the petroleum sector.  These analyses both forecast petroleum production, which was ultimately used

as the activity driver for each region for emissions in 2018, per Equation 4.  

ܨܣ௡௢௜௚௘௥ିଶ଴ଵଵ ൈ

ை௜௟௉ೝ೐೒೔೚೙	ష	మబభఴ

ை௜௟௉ೝ೐೒೔೚೙ష	మబభభ

ൌ ܨܣ௡௢௜௚௘௥ି	ଶ଴ଵ଼     Equation 4

Where:

AFregion‐2011 = regional activity factor for the 2011 inventory

OilPregion – 2018 = regional oil production projected in EIA’s 2014 AEO for 2018

OilPregion – 2011 = regional oil production in EIA’s 2014 AEO for 2011

AFregion – 2018 = regional activity factor for 2018 inventory projection

All of the emission sources in the Oil Transportation and the Oil Refining segments were driven using the

AEO 2014 Early Release “Petroleum and Other Liquids Supply and Disposition” forecast. Most of the

sources in the Oil Production segment were driven by the API Quarterly Well Completions Report, as

detailed in section C.3.2, but several source were driven by the “Petroleum and Other Liquids Supply

and Disposition” forecast. These sources include oil tanks, oil tank dump valve venting, floating roof

tanks, sales areas, and flares. Also, the offshore activity factors were driven by the AEO 2014 Early

Release.

C.3.2. API’s Quarterly Well Completions Report

The approach used to estimate oil well counts was the same as that used for gas well counts, based on

continued well completions at the current rate through 2018. ICF used API’s Quarterly Well Completions

Report as the source to drive a majority of the emission sources in the Oil Production segment. The

completions data was used to determine how many active wells would be in operation in 2018, which

was then used to drive the emission sources in Oil Production.

The 2012 count of completions was assumed to be constant each year through 2018. However, some

wells are shut‐in and abandoned each year, so this was accounted for well count forecast. To determine

the number of wells shut‐in per year, ICF compared the growth rate of wells to the growth of oil

production in each region. A shut‐in percentage, between 0.1% and 5%, was then assigned to each

region in order to align the well count growth with the oil production growth. The percentages used in

each region are listed below.
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Annual Oil Well Retirement Rate by Region

Region Oil Well

Retirement Rate

Northeast 4.0%

Gulf Coast 0.1%

Midcontinent 0.5%

Southwest 5.0%

Rocky Mountain 2.0%

West Coast 2.5%

Alaska 5.0%

  

Once the updated well counts were set for each region, a ratio of wells in 2018 to wells in 2011 was

used to drive the activity for all the emissions sources in the Oil Production segment, except those listed

in section C.3.1. The only exceptions to this were the oil well completion values which used the 2012 oil

well completion values directly from the API Quarterly Well Completions Report. Also, it is assumed that

no new high bleed pneumatics are installed.

C.4. Natural Gas and Petroleum Inventory Emission Factors

For nearly every source category, ICF used the same emission factors for each emissions source as those

used in development of the 2011 inventory. The exceptions are listed out individually below.  

C.4.1. Sources with Different Emission Factors

The following emission sources (with their respective industry segments) had different emission factors

between 2011 and 2018.

 Heaters (Gas Production)

 Separators (Gas Production)

 Dehydrators (Gas Production)

 Meters/Piping (Gas Production)

 Pneumatics (Gas Processing)

The four emission sources in the Gas Production segment used different emission factors between 2011

and 2018 in only two of the regions, the Northeast and Midcontinent. This is because the 2011 baseline

year uses the same emission factors that the EPA Inventory uses, which come from the 1996 GRI study
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and are divided into Eastern and Western regions. In 2011, the Northeast and Midcontinent regions use

the Eastern emission factors, which are substantially lower than the Western emission factors. The

Eastern emission factors describe equipment associated with older, lower producing gas wells that

existing in most of the Northeast and Midcontinent when the GRI study was undertaken in 1992.

However, most of the new wells in these regions are much higher producing wells, better characterized

by the Western emission factors from the 1996 GRI study. Therefore, the incremental increases in

equipment counts associated with these wells (the four sources listed above) have the Western

emission factors applied to them, while the older equipment already in place in 2011 have the lower

Eastern emission factors applied to them.

For pneumatics in Gas Processing, all new pneumatic devices must be zero bleed devices, per NSPS

subpart OOOO. Therefore, the incremental increase in pneumatic devices in 2018 use an emission factor

of zero emissions, assuming that all the devices are zero bleed.

C.5. Emission Reductions – NSPS subpart OOOO

The new 2018 forecast of emissions was then modified to reflect the expected emission reductions as a

result of NSPS subpart OOOO.  Per the NSPS, the following sources would see emissions reductions as a

result of regulation:

 Gas Well Completions with Hydraulic Fracturing

 Gas Well Workovers with Hydraulic Fracturing

 Pneumatic Devices

 Reciprocating Compressors (excluding Production and Transmission sectors)

 Centrifugal Compressors (excluding Production and Transmission sectors)

 Storage Tanks

 Dehydrators

The total emissions from these sources, including reductions resulting from regulation controls, were

calculated per Equation 6.

൫ܨܣ௡௢௜௚௘௥ିଶ଴ଵ଼ ൈ ܨܧଶ଴ଵଵ൯ െ ቀܨܣ௡௢௜௚௘௥ିଶ଴ଵ଼ ൅ ܨܣ௡௢௜௚௘௥ିଶ଴ଵଵሺܱܶ െ 1ሻቁ ൈ ܨܧଶ଴ଵଵ ൈ ܲܥ ൈ ܴ ൌ ܧଶ଴ଵ଼

            Equation 6

Where:

AFregion – 2018 = regional activity factor for the 2018 inventory

EF2011 = emission factor used in the 2011 inventory

AFregion – 2011 = regional activity factor for the 2011 inventory

TO = turnover rate (assumed to be 1% for pneumatics in all sectors and 1% for reciprocating  

and centrifugal compressors in gathering/boosting and processing)
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PC = population coverage, estimated from NSPS Background Technical Support Document46

R = reduction percent, estimated from NSPS Background Technical Support DocumentError!

Bookmark not defined.

E2018 = estimate of emissions from the respective source category in 2018

                                                            

46 New Source Performance Standards Background Technical Support Documents, available at:

http://www.epa.gov/airquality/oilandgas/pdfs/20120418tsd.pdf and

http://www.epa.gov/airquality/oilandgas/pdfs/20110728tsd.pdf
ICF International D‐1 March 2014

Appendix D. Methane Mitigation Technologies

This section provides additional information on some of the available methane mitigation technologies.

Most of the performance data are as reported to the EPA Gas STAR program and may have been

modified for the analysis in this study.

D.1. Installing Plunger Lift Systems in Gas Wells

Plunger lift systems are cost‐effective methods for removing the buildup of liquids inside a gas well.

Plunger lift systems increase production by maintaining gas flow while significantly reducing methane

emissions that would have otherwise occurred with well blowdown operations. A plunger lift removes

accumulated fluids by using the downhole gas pressure to lift a column of accumulated fluid out of the

well. The plunger lift system helps to maintain gas production and may reduce the need for other

remedial options.

D.1.1. Technology Background

Liquid loading of the wellbore can impede and sometimes halt gas production. Gas flow through the well

is often maintained by removing accumulated fluids through venting the well to atmospheric pressure,

also known as “blowing down” the well. Installing a plunger lift system removes the accumulated liquids

with the added benefits of increasing production and recovering gas that would otherwise be emitted

through a well blowdown.

Environmental Effectiveness and Key Factors: Installing Plunger Lift Systems

Environmental

Effectiveness CO2 CH4 N2O

Typical abatement

efficiency for key GHGs

(primary abatement

metrics), %

100% (assuming the gas

lifting the plunger is

recovered to a sales line)

100% (assuming the gas

lifting the plunger is

recovered to a sales line)

0%

Factors affecting efficiency Depth and pressure of the

well

Depth and pressure of the

well

Limits of technical

feasibility

Each plunger lift system is subject to a minimum requirement for each well

application. The minimum gas flow is 400 standard cubic feet (scf) per barrel (bbl) of

fluid per 1,000 feet of well depth. Additionally, wells must have a shut‐in wellhead

pressure that is 1.5 times the sales line pressure.

The potential amount of methane available for recovery will increase as the pressure

and the venting frequency increase.

Plunger lift systems rely on the natural buildup of gas pressure, as the gas well becomes shut‐in from

liquid accumulation to lift a plunger remove the accumulated liquids. To recover the gas, the sales line

pressure must be connected to the wellhead and the pressure must be less than the downhole pressure
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of the well. This enables gas to flow into the sales line, preventing emissions and continuing well

production.

Cost Benefit Analysis: Installing Plunger Lift Systems47

CapEx per well and per unit

production (2013 USD):

$2,400 to $9,600 per plunger lift system

OpEx per well and per unit

production (2013 USD):

$860 to $1,600 per year – Plunger lift maintenance requires routine

inspection of the lubricator and plunger. Typically, these items need to be

replaced every 6 to 12 months.

Revenue per well and per unit

production:

$18,800 to $73,000 per year (at $4.00 per Mcf of gas)

Payback Period: 1 to 7 months (at $4.00/Mcf of gas)

D.1.2. Technology Penetration

Plunger lifts are a fully developed and widespread technology for gas wells with vertical orientation, and

are more often viewed as production enhancers than as a methane mitigation technology. One service

provider was quoted by the EPA that in 2008 there were about 150,00048 plunger lifts in service,

approximately 30 percent of gas wells at the time. In 2012, API/ANGA released a study showing that 36

percent of their survey well population had operational plunger lifts.49  

Plunger lifts, however, are still being adapted for use in gas wells with a deviated orientation such as

horizontal wells. Few studies have been done on the use of plunger lifts on horizontal wells. Therefore,

more research must be done to determine the penetration of plunger lifts on horizontal wells and

effectiveness of plunger lifts installed on horizontal wells.

D.2. Replacing Wet Seals with Dry Seals in Centrifugal Compressors

Centrifugal compressors are used in the production sector to pressurize gas in pipelines to transport gas

downstream.  Wet seal centrifugal compressors are a large source of emissions, as a result of their wet

seal degassing operations. Seal oil (wet seals) on the rotating shafts of centrifugal compressors prevent

the high‐pressure natural gas from escaping the compressor casing. These wet seals act as a barrier to

the high pressure natural gas. Natural gas however, becomes entrained in the seal oil, which leads to

emissions as the seal oil degasses to the atmosphere. By converting to dry seals, which use high pressure

                                                            

47 Plunger Lift System Economics extracted from U.S. EPA Lessons Learned: Installing Plunger Lift Systems in Gas Wells

http://epa.gov/gasstar/documents/ll_plungerlift.pdf    48 Robinson, D. (2012) Liquids Unloading options for Natural Gas Wells. 2012 Natural Gas STAR Annual Implementation

Workshop. April 12, 2012: Denver, Colorado. http://www.epa.gov/gasstar/documents/workshops/2012‐annual‐

conf/robinson.pdf

49 API (2012) API/ANGA Information on Gas Well Liquids Unloading. EPA Stakeholder Workshop September 13‐14, 2012:

Washington D.C. http://www.epa.gov/climatechange/Downloads/ghgemissions/2012Workshop/Smith_BP.pdf
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gas seals instead of oil, lower emissions are achieved while reducing power requirements and improving

compressor performance and reliability.

D.2.1. Technology Background

Centrifugal compressors require seals around the rotating shaft to prevent gases from escaping where

the shaft exits the compressor casing. Typically, compressors have two seals, one on each end of the

compressor. Wet seals use oil, which is circulated under high pressure three rings around the

compressor shaft, which creates a barrier against the compressed gas escaping. This oil barrier prevents

gas from escaping, however a significant amount of gas is absorbed by the oil under the higher

pressures of the compressor. Since this affects the integrity of the seal oil, it must be degassed through

the use of process equipment and recirculated. The recovered methane is commonly vented to the

atmosphere.

Dry seals on centrifugal compressor

Environmental Effectiveness and Key Factors: Replacing Wet Seals with Dry Seals on Centrifugal Compressors

Environmental

Effectiveness CO2 CH4 N2O

Typical abatement

efficiency for key GHGs

(primary abatement

metrics), %

97% 97% 0%

Factors affecting efficiency See below See below   

Limits of technical

feasibility

The compressor pressure must be below 3,000 psi and the temperature must be

below 300o F. Furthermore; compressors should not be towards the end of their life.

To prevent the absorption of gas into the seals, dry seals can be installed which operate mechanically

under the opposing force created by hydrodynamic grooves and static pressure. Dry seals create a
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barrier, forcing the gas to leak down the shaft where it has a small chance of leaving the compressor

between the rotating and stationary rings. Dry seals substantially reduce methane emissions, operating

costs, and enhance compressor efficiency.

Cost Benefit Analysis: Replacing Wet Seals with Dry Seals on Centrifugal Compressors50

CapEx per well and per unit

production (2013 USD):

$400,000 (Seals + Engineering Installation)

OpEx per well and per unit

production (2013 USD):

$17,500

Revenue per well and per unit

production:

$180,500 per year (at $4.00/Mcf of gas)

Payback Period: 29 months (at $4.00/Mcf of gas)

D.2.2. Technology Penetration

Over the past decade, dry seals have become favored over wet seal compressors because they do not

require a separate seal oil circulation and regeneration system. For offshore platforms this is ideal due

to space limitations and for gathering and boosting operations it results in less operational and

maintenance costs. One vendor was quoted that almost 90 percent of new centrifugal compressors sold

are equipped with dry seals. Dry seal retrofits are not as common due to the high upfront costs and

downtime losses incurred. Wet Seal Degassing Recovery System for Centrifugal Compressors

D.3. Wet Seal Degassing Recovery System for Centrifugal

Compressors

Centrifugal compressors are widely used in the production of natural gas. Seals on the rotating shafts of

centrifugal compressors prevent the high‐pressure natural gas from escaping the compressor casing.

Wet seals use high‐pressure oil (wet seals) as a barrier against escaping gas. To prevent emissions from

these centrifugal compressors, one can capture the seal oil degassing stream from a small

disengagement vessel and recycle it back into the compressor suction, or as high pressure turbine fuel

gas, or low pressure fuel gas to heaters.

D.3.1. Technology Background

Centrifugal compressor wet seal degassing recovery systems have been demonstrated installed as a

cost‐effective alternative to dry seals for new compressors. They use commercially available equipment

and projected to be much less expensive than replacing wet seal systems with dry seals but have not

been commercially demonstrated for retrofit applications.  

                                                            

50 Economics extracted from U.S. EPA Lessons Learned: Replacing Wet Seals with Dry Seals in Centrifugal Compressors

http://epa.gov/gasstar/documents/ll_wetseals.pdf
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There are multiple options for the degassing stream recovered through this system including: the gas

can be sent as low pressure fuel to a boiler, high pressure fuel to a turbine, recycled back to the

compressor suction, or sent to a flare. All four options significantly reduce methane emissions from seal

oil degassing operations.

Wet seal degassing recovery system for centrifugal compressors ‐ Source: U.S. EPA

Environmental Effectiveness and Key Factors: Wet Seal Recovery System for Centrifugal Compressors

Environmental

Effectiveness CO2 CH4 N2O

Typical abatement

efficiency for key GHGs

(primary abatement

metrics), %

Up to 100% (Assuming

recovered gas is not

flared)

Up to 99% N/A

Factors affecting efficiency Depending on the use of

the recovered degassing

emissions.

Depending on the use of

the recovered degassing

emissions.

Limits of technical

feasibility

“Knock‐out” vessels to recover any seal oil mist from the recovered gas, if the

gas is to be used as fuel. Piping capacity must exist to use recovered

degassing emissions.
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Cost Benefit Analysis: Wet Seal Recovery System for Centrifugal Compressors

CapEx per One Centrifugal

Compressor (2013 USD):

$33,700 (Cost for seal oil gas separator, seal oil gas demister for

low quality gas, and seal oil gas demister for high quality gas)

OpEx per One Centrifugal

Compressor (2013 USD):

Minimal

Revenue per One Centrifugal

Compressor :

$120,000 (at $4.00/Mcf of gas)

Payback Period: 3 months (at $4.00/Mcf of gas)

D.3.2. Technology Penetration

Wet seal degassing recovery systems are feasible but are not currently not available as an off‐the‐shelf

technology. This technology has only been documented as part of an Original Equipment Manufacturer

design, meaning the wet seal degassing recovery system was installed with the centrifugal compressor

station.51 There is no documentation to date reporting the implementation of this technology as a

retrofit to an existing centrifugal compressor. Operators will likely need to work with the original

compressor manufacturer to have this technology installed.

D.4. Installing Vapor Recovery Units on Storage Tanks

Crude oil storage tanks are used to hold oil for brief periods of time in order to stabilize flow between

production wells and pipeline or trucking transportation sites. The crude oil experiences a drop in

pressure as it is transferred to the crude oil storage tank. Due to this drop in pressure, light

hydrocarbons vaporize or “flash out” and collect in the space between the liquid and the fixed roof of

the tank. The vapors are vented to the atmosphere to avoid pressure build‐up. Vapor Recovery Units

(VRUs) are installed on crude oil storage tanks to prevent these vented emissions.

D.4.1. Technology Background

Underground crude oil contains many dissolved light hydrocarbons. These hydrocarbons typically flash

out during production as well as through a series of separators. Once it has gone through separators, the

crude oil is pumped into a storage tank to await sale and transportation off site; the remaining light

hydrocarbons flash out of the crude, into the vapor space of the tank. The same principles apply for

condensate. These resulting vapors are typically vented or flared. The composition of these vapors

varies, but typically include methane, propane, butane, and ethane as well as VOCs and HAPs.

                                                            

51 Smith, R. (2012) Centrifugal Compressor Wet Seals Seal Oil Degassing & Control. Natural Gas STAR Annual Workshop; Denver,

CO. http://www.epa.gov/gasstar/documents/workshops/2012‐annual‐conf/smith.pdf
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VRUs are installed to recover these vapors to prevent emissions and reduce flaring. VRUs use a

compressor and a suction line, to pull the vapors into a scrubber tank, where the recovered

hydrocarbons can then be transported to multiple places, including the sales line.

VRU process schematic  ‐ Source: Evans & Nelson (1968)

Environmental Effectiveness and Key Factors: Installing VRUs on Storage Tanks

Environmental

Effectiveness CO2 CH4 N2O

Typical abatement

efficiency for key GHGs

(primary abatement

metrics), %

95% 95% 0%

Factors affecting efficiency The reliability of the

suction scrubber and

compressor

The reliability of the

suction scrubber and

compressor

Assuming the storage tank

vented emissions were

not previously flared.

Limits of technical

feasibility

VRUs capture approximately 95% of flashing losses, from storage tanks. VRUs success

depends on the lines connecting the tanks to the compressor, as well as the

compressor which creates the suction.
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

Industries

Methane Mitigation Technologies

ICF International D‐8 March 2014

Cost Benefit Analysis: Installing VRUs on Storage Tanks52

CapEx per well and per unit

production (2013 USD):

$44,500 to $129,000

OpEx per well and per unit

production (2013 USD):

$9,100 to $20,800

Revenue per well and per unit

production:

$20,000 to $380,000 per year (at $4.00/Mcf of gas)

Payback Period: 4 to 51 months (at $4.00/Mcf of gas)

D.4.2. Technology Penetration

VRUs are a widely adopted methane mitigation technology.  There are several service providers that

implement VRUs across the United States including HY‐BON, Exterran, and COMM Engineering.  

D.5. Converting High‐Bleed Pneumatic Devices to Low‐Bleed

Pneumatic devices powered by pressurized natural gas are used widely in the natural gas industry as

liquid level controllers, pressure regulators, and valve controllers. Pneumatic devices vent natural gas as

a part of normal operations and are one of the biggest sources of emissions in the production sector.

Older pneumatic devices can have a relatively high bleed rate and emissions can be significantly reduced

by converting the devices to low‐bleed models.

D.5.1. Technology Background

The volume of natural gas vented from pneumatic devices varies by model and age. High‐bleed

pneumatic devices vent over six standard cubic feet of CH4 per hour per device. The average high‐bleed

pneumatic device vents 330 standard cubic feet CH4 per day per device. Low‐bleed pneumatic devices

vent six or less standard cubic feet of CH4 per hour per device. Low‐bleed pneumatic devices vent on

average to 52 cubic feet CH4 per day per device. By retrofitting or switching high‐bleed pneumatic

devices to low‐bleed pneumatic devices, emissions are reduced. Not all pneumatic device applications

are appropriate for low‐bleed devices, but field experience has shown that up to 80 percent of all high‐

bleed devices can be replaced with low‐bleed equipment or retrofitted.

                                                            

52 Economics extracted from U.S. EPA Lessons Learned: Installing Vapor Recovery Units on Storage Tanks

http://epa.gov/gasstar/documents/ll_final_vap.pdf
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

Industries

Methane Mitigation Technologies

ICF International D‐9 March 2014

Pneumatic device schematic ‐ Source: U.S. EPA Lessons Learned

Environmental Effectiveness and Key Factors: Converting High‐Bleed Pneumatics to Low‐Bleed

Environmental

Effectiveness CO2 CH4 N2O

Typical abatement

efficiency for key GHGs

(primary abatement

metrics), %

N/A 84% N/A

Factors affecting efficiency    See below.

Limits of technical

feasibility

Methane abatement efficiency is dependent upon the initial bleed rate of the high‐

bleed rate device. Bleed rates will vary with pneumatic gas supply pressure, actuation

frequency, and age or condition of the equipment.

   
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

Industries

Methane Mitigation Technologies

ICF International D‐10 March 2014

Cost Benefit Analysis: Converting High‐Bleed Pneumatics to Low‐Bleed53

CapEx per well and per unit

production (2013 USD):

$260 to $420 (Change to low‐bleed at end of life)

$2,300 (Early replacement of high‐bleed unit)

$840 (Retrofit)

OpEx per well and per unit

production (2013 USD):

N/A

Revenue per well and per unit

production:

$200 to 800  (Change to low‐bleed device at end of life)

$1,040 (Early replacement of high‐bleed unit)

    $920 (Retrofit)

(All at $4.00/Mcf of gas)

Payback Period: 4 to 25 months (Change to low‐bleed at end of life at $4.00/Mcf of gas)

27 months (Early replacement of high‐bleed unit at $4.00/Mcf of gas)

11 months (Retrofit at $4.00/Mcf of gas)

D.5.2. Technology Penetration

Low bleed pneumatic devices are a mature technology that has been commercially available since the

1990s. Low bleed devices are routinely used for new systems and replacements. Directed replacement

for emission reductions are less common.

D.6. Reciprocating Compressor Rod Packing Replacement

Rod packing is the seal that prevents gas from leaking around the displacement rod in a reciprocating

compressor – similar in concept to the piston rings in a car engine. Emissions from packing are

dependent upon the compressor cylinder pressure, the fitting and alignment of the packing parts, and

the amount of wear on the rings and rod shaft rod. By developing a timely schedule for the replacement

of rod packing systems in reciprocating compressors, one can significantly reduce methane emissions

and increase savings.

D.6.1. Technology Background

Rod packing replacement entails replacing a set of flexible rings that fit around the shaft, which creates

a seal against high pressure gas leakage. The packing rings are lubricated with circulating oil to reduce

wear, however over time these packing rings lead to more gas leaking.

By organizing company‐specific financial goals, companies can determine an emission threshold at

which it is cost‐effective to replace rings and rods. Under the best conditions, new packing systems

properly installed on a smooth, well‐aligned shaft can be expected to leak a minimum of 11.5 standard

cubic feet/hour. Higher leak rates are a consequence of fit, alignment of the packing parts, and wear.

Leaking gases are vented to the atmosphere.

                                                            

53 Economics extracted from U.S. EPA Lessons Learned: Options for Reducing Methane Emissions From Pneumatic Devices in

the Natural Gas Industry. http://epa.gov/gasstar/documents/ll_pneumatics.pdf
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

Industries

Methane Mitigation Technologies

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Reciprocating compressor and rod packing components – Source: U.S. EPA Lessons Learned

Environmental Effectiveness and Key Factors: Reciprocating Compressor Rod Packing Replacement

Environmental

Effectiveness CO2 CH4 N2O

Typical abatement

efficiency for key GHGs

(primary abatement

metrics), %

N/A Up to 98% N/A

Factors affecting efficiency    See Below.

Limits of technical

feasibility

The timing of replacement will affect abatement efficiency.

Cost Benefit Analysis: Reciprocating Compressor Rod Packing Replacement54

CapEx per well and per unit

production (2013 USD):

$2,000 every three years, or $670 per year

OpEx per well and per unit

production (2013 USD):

N/A

Revenue per well and per unit

production:

$3,500 (at $4.00/Mcf of gas)

Payback Period: 7 months (at $4.00/ Mcf of gas)

                                                            

54 Economics extracted from U.S. EPA Lessons Learned: Reducing Methane Emissions From Compressor Rod Packing Systems.

http://epa.gov/gasstar/documents/ll_rodpack.pdf
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

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Methane Mitigation Technologies

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D.6.2. Technology Penetration

Reciprocating rod packing is a general maintenance practice that is commonly performed on

reciprocating compressors as they age. Rod packing replacement as a mitigation technology however is

a work practice that involves proactively monitoring the rod packing leak rate and replacing the rod

packing when it is economic to do so.  

D.7. Convert Natural Gas‐Driven Chemical Pumps (Kimray Pumps)

Chemical pumps are used for a variety of purposes at a well‐site. If there is no source of electricity

nearby, operators drive their pumps using the mechanical energy of the natural gas from their well(s).

Natural gas driven pumps however vent the natural gas used to drive them. Venting of methane as well

as VOCs and HAPs from pneumatic pumps is eliminated by converting the pumps from being natural gas

driven to either instrument air‐driven or electric.

D.7.1. Technology Background

The most common application of natural gas driven pumps at well sites is for chemical injection and to

circulate the glycol in a dehydrator. Instrument air pumps require that the operator install an air

compressor, which also requires electricity, to pressurize air to drive the pumps. Electric pumps may

either require installing a generator or solar panels or evaluating if a connection to the grid is feasible.

Solar‐charged glycol pump (Source: BP)
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

Industries

Methane Mitigation Technologies

ICF International D‐13 March 2014

Environmental Effectiveness and Key Factors: Convert Natural Gas‐Driven Chemical Pumps

Environmental

Effectiveness CO2 CH4 N2O

Typical abatement

efficiency for key GHGs

(primary abatement

metrics), %

100% 100% N/A

Factors affecting efficiency See Below. See Below.

Limits of technical

feasibility

Dependent on if the air‐compressor or electric driven generator is

powered by hydrocarbons, Electrical requirements for air compressor, as

well as capacity to install piping between air compressor and the glycol

circulation pump. Weather can also affect the reliability of solar powered

electric‐driven pumps.

Cost Benefit Analysis: Convert Natural Gas‐Driven Chemical Pumps55

CapEx per well and per unit

production (2013 USD):

$1,200 to $12,000

OpEx per well and per unit

production (2013 USD):

$120 to $1,200 (Electricity costs)

Revenue per well and per unit

production:

$10,000 (at $4.00/Mcf of gas)

Payback Period: 1 to 16 months (at $4.00/Mcf of gas)

D.7.2. Technology Penetration

Electric pumps and energy exchange pumps (for glycol dehydrators) are common technologies. Many

companies have reported replaced pneumatic pumps with electric pumps through the Natural Gas STAR

Program.  

D.8. Conducting Leak Detection and Repair Programs

Leak Detection and Repair (LDAR) programs are implemented to identify and repair leaking components

where it is cost‐effective. Through specialized infrared (IR) cameras and a trained team, hydrocarbon

emissions can be detected at a production facility.

D.8.1. Technology Background

Unintentional equipment leaks may arise due to normal wear and tear, improper or incomplete

assembly of components, inadequate material specification, manufacturing defects, damage during

installation or use, corrosion, fouling and/or annual temperature change cycles. LDAR programs

concentrate on components that are prone to leak enough methane to make repair cost‐effective. A

                                                            

55 Economics extracted from U.S. EPA PRO Fact Sheet No. 202: Convert Natural Gas‐Driven Chemical Pumps

http://epa.gov/gasstar/documents/convertgasdrivenchemicalpumpstoinstrumentair.pdf
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

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Methane Mitigation Technologies

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specially trained team using an infrared (IR) camera can search for hydrocarbon emissions throughout a

facility. After identifying the leaking equipment, repairs are made in cases where the leak poses a safety

threat or when the repairs are economically feasible (i.e. benefits outweigh the costs).

IR camera in use for DI&M ‐ Source: Leak Surveys, Inc.

Environmental Effectiveness and Key Factors: Conduction Directed Inspection and Maintenance

Environmental

Effectiveness CO2 CH4 N2O

Typical abatement

efficiency for key GHGs

(primary abatement

metrics), %

Up to 100% (Assuming

leak is repaired)

Up to 100% (Assuming

leak is repaired) N/A

Factors affecting efficiency See below. See Below.

Limits of technical

feasibility

The effectiveness of the program will vary by site and company. The

effectiveness will vary depending on the number of leaks found and repaired.

Reliability depends on the thoroughness and completeness of program, as

well as the quality of leak repairs.
Economic Analysis of Methane Emission Reduction Opportunities in the U.S. Onshore Oil and Natural Gas

Industries

Methane Mitigation Technologies

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Cost Benefit Analysis: Conducting LDAR56

CapEx per well and per unit

production (2013 USD):

$124,000 (IR Camera)

OpEx per well and per unit

production (2013 USD):

$10 ‐ $6,900 (Depending on repair cost)

Revenue per well and per unit

production:

$1,500 (at $4.00/Mcf of gas)

Payback Period: Dependent on repair cost

D.8.2. Technology Penetration

The technology to perform this methane mitigation practice is common and widely available. Facilities

employ technologies such as infrared cameras or handheld leak detection equipment.  

                                                            

56 Economics extracted from U.S. EPA Lessons Learned: Conduct DI&M at Remote Sites

(http://epa.gov/gasstar/documents/conductdimatremotefacilities.pdf)