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CONTENTS 

Acknowledgments.......................................................................................................................... vi 

Abstract......................................................................................................................................... vii 

Acronyms and Abbreviations ...................................................................................................... viii 

1 Introduction ............................................................................................................................. 1 

2 Methods ................................................................................................................................... 3 

2.1 Life-Cycle Analysis Approach ....................................................................................... 3 

2.2 Data Sources and Key Parameters Associated with Natural Gas Recovery .................. 4 

2.2.1 Estimated Ultimate Recovery............................................................................. 7 

2.2.2 Well Design, Drilling, and Construction............................................................ 8 

2.2.3 Hydraulic Fracturing and Management of Flowback Water .............................. 9 

2.2.4 Well Completions ............................................................................................. 13 

2.2.5 Liquid Unloadings and Miscellaneous Leakage and Venting .......................... 14 

2.2.6 Recovery Pipeline to Compression Station ...................................................... 16 

2.2.7 Methane Reductions from Natural Gas Recovery............................................ 17 

2.3 Data for Natural Gas Processing, Transmission, Storage, and Distribution ................ 18 

2.4 GREET Life-Cycle Analysis ........................................................................................ 21 

2.4.1 Treatment of Emissions from Early 1990s Natural Gas Systems 

to Current Systems ........................................................................................... 21 

2.4.2 End-Use Efficiencies ........................................................................................ 22 

2.4.3 Greenhouse Gas Global Warming Potentials ................................................... 23 

3 Results and Discussion ......................................................................................................... 25 

3.1 GHG Emissions by End Use ........................................................................................ 25 

3.2 Detailed Breakdown of GHG Emissions for Fuel Pathways ....................................... 27 

3.3 Examination of Uncertainty of Key Parameters with Respect 

to Life-Cycle Emissions ............................................................................................... 28 

4 Summary and Implications ................................................................................................... 31 

5 References............................................................................................................................. 33 

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FIGURES 

1 U.S. Shale Gas Plays ................................................................................................................1
 

2 System Boundary for Shale and Conventional NG Pathways. ................................................3
 

3 Life-Cycle GHG Emissions per kWh of Electricity Produced. Two time horizons — 

100-year and 20-year — are considered.................................................................................25
 

4 Well-to-Wheels Life-Cycle GHG Emissions per VMT – Passenger Car. Two time 

horizons — 100-year and 20-year — are considered. ............................................................26
 

5 Well-to-Wheels Life-Cycle GHG Emissions per VMT – Transit Bus. Two time 

horizons — 100-year and 20-year — are considered. ............................................................27
 

6 Life-Cycle GHG Emissions per MJ of Fuel Produced and Combusted for Both 100-year 

and 20-year GWPs..................................................................................................................28
 

7 Sensitivity Analysis Results for Shale and NG Pathways (100-Year Time Horizon) ...........29
 

8 Sensitivity Analysis Results for Shale and NG Pathways (20-Year Time Horizon) .............30
 

TABLES 

1 Selected Activity Factors for the Recovery of Natural Gas .....................................................4
 

2 Comparison of Changes to Selected EPA Emissions Factors ..................................................5
 

3 Key Parameters for Natural Gas Simulation in GREET ..........................................................6
 

4 Lifetime Production Estimates According to Play ...................................................................7
 

5 Material Requirements for Drilling and Constructing a Typical Well by Play ........................9
 

6 Typical Range of Water Requirements Per Well for Fraccing Activities by Shale Play .......10
 

7 Estimated Fraccing Fluid Components According to Average Values from Selected 

Marcellus Wells......................................................................................................................11
 

8 Assumptions in Determining the Transportation and Management of Hydraulic 

Fracturing Fluids ....................................................................................................................12
 

9 Fuel and Energy Requirements for the Management of Frac Fluid .......................................13
 

10 Average Material and Energy Requirements for Pipeline per mmBtu of Natural Gas ..........17
 

11 Selected Activity Factors for the Processing, Transmission and Storage, and 

Distribution Sectors................................................................................................................19
 

12 Derivation of Lelieveld et al.’s Estimate of Natural Gas Losses during Transmission 

and Distribution in Russia ......................................................................................................20
 

13 Comparison of Current GREET Emissions Factors with Harrison et al. ...............................21
 

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TABLES (CONT.) 

14 End-Use Efficiency Assumptions for GREET Simulations ...................................................23
 

15 Global Warming Potentials of Greenhouse Gases .................................................................24
 

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ACKNOWLEDGMENTS 

This study was supported by the Vehicle Technologies Program within the Office of 

Energy Efficiency and Renewable Energy of U.S. Department of Energy under Contract Number 

DE- AC02-06CH11357. We would like to thank Kevin Stork and Linda Bluestein from the 

Vehicle Technologies Program for their support. We also thank our Argonne National 

Laboratory colleagues Chris Harto for assistance in developing the methods for the management 

of flowback water from shale gas wells and Shabbir Shamsuddin and Michael McLamore for 

their expertise in natural gas pipeline infrastructure. Finally, we are grateful to Lisa Hanle, 

U.S. Environmental Protection Agency, and Douglas Sechler, ICF International, for providing 

additional information on the critical assumptions of EPA’s revised emissions estimates. 

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LIFE-CYCLE ANALYSIS OF SHALE GAS AND NATURAL GAS 

Corrie E. Clark, Jeongwoo Han, Andrew Burnham, Jennifer B. Dunn, Michael Wang 

Center for Transportation Research, Argonne National Laboratory 

December 2011 

ABSTRACT 

The technologies and practices that have enabled the recent boom in shale gas production 

have also brought attention to the environmental impacts of its use. Using the current state of 

knowledge of the recovery, processing, and distribution of shale gas and conventional natural 

gas, we have estimated up-to-date, life-cycle greenhouse gas emissions. In addition, we have 

developed distribution functions for key parameters in each pathway to examine uncertainty and 

identify data gaps — such as methane emissions from shale gas well completions and 

conventional natural gas liquid unloadings — that need to be addressed further. Our base case 

results show that shale gas life-cycle emissions are 6% lower than those of conventional natural 

gas. However, the range in values for shale and conventional gas overlap, so there is a statistical 

uncertainty regarding whether shale gas emissions are indeed lower than conventional gas 

emissions. This life-cycle analysis provides insight into the critical stages in the natural gas 

industry where emissions occur and where opportunities exist to reduce the greenhouse gas 

footprint of natural gas. 

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ACRONYMS AND ABBREVIATIONS 

API American Petroleum Institute 

Argonne Argonne National Laboratory 

AGR acid gas removal 

CNG compressed natural gas 

EIA Energy Information Administration 

EPA U.S. Environmental Protection Agency 

EUR estimated ultimate recovery 

GAO U.S. Government Accountability Office 

GHG greenhouse gas 

GREET Greenhouse gases, Regulated Emissions, and Energy use in Transportation model 

GWP global warming potential 

IPCC Intergovernmental Panel on Climate Change 

LCA life-cycle analysis 

LUG lost and unaccounted for gas 

NESHAP National Emission Standards and Hazardous Air Pollutants 

NG natural gas 

NGCC natural gas combined cycle 

REC reduced emission completion 

SG shale gas 

T&S transmission and storage 

VMT vehicle-mile traveled 

WTW well-to-wheels 

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Units of Measure 

bbl barrel(s) 

Bcf billion cubic feet 

Btu British thermal unit(s)
 

ft foot, feet 

gal gallon(s) 

gCO2e/MJ grams of carbon dioxide equivalent per megajoule 

gCO2e/kWh grams of carbon dioxide equivalent per kilowatt-hour of electricity generated 

gCO2e/mile grams of carbon dioxide equivalent per mile 

h hour(s) 

hp horsepower 

kWh kilowatt-hour(s)
 

liter(s) 

m meter(s) 

Mcf thousand cubic feet 

MJ megajoule(s) 

mmBtu million-Btu 

s second(s) 

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1 INTRODUCTION 

Production of natural gas (NG) from shale formations first occurred when the first gas 

well was completed in 1821 in Fredonia, New York; however, the low permeability of shale 

formations posed both technical and economic challenges to large-scale development. Largescale shale gas production started in the Barnett Shale in the 1980s, and by 2006, through 

advances in drilling technologies and higher NG prices, the success in the Barnett Shale led to 

rapid expansion into other formations, including the Haynesville, Marcellus, and Fayetteville 

shales. The development of this resource has generated interest in expanding NG usage in such 

areas as electricity generation and transportation. 

It is anticipated that shale gas will provide the largest source of growth in the U.S. natural 

gas supply through 2035. In 2009, shale gas contributed 16% of the U.S. natural gas supply. By 

2035, it is estimated that its contribution will increase to 47% of total U.S. production of natural 

gas, with this anticipated growth in production raising the natural gas contribution to electricity 

generation from 23% in 2009 to 25% in 2035 (EIA 2011a). 

The Energy Information Administration (EIA) assumes that there are 827 trillion cubic 

feet of technically recoverable shale gas in the United States. Shales that are considered to be 

important include the Marcellus, Haynesville, Fayetteville, and Barnett. Other important plays 

include the Antrim, Eagle Ford, New Albany, and Woodford (Figure 1). 

FIGURE 1 U.S. Shale Gas Plays (Veil 2010) 

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With significant potential growth in unconventional gas production, the life-cycle 

impacts of natural gas may change. “Unconventional gas” refers to gas produced from lowpermeability reservoirs, which include tight sands, coal bed methane, and shale gas reservoirs. 

Argonne National Laboratory (Argonne) conducted a life-cycle analysis to compare the 

materials, energy requirements, and emissions associated with producing, processing, 

transporting, and consuming natural gas produced from conventional natural gas resources and 

shale gas resources. Argonne’s GREET (Greenhouse gases, Regulated Emissions, and Energy 

use in Transportation) model had previously developed the conventional gas pathway 

(Wang et al. 2007; Brinkman et al. 2005; Wang 1999; Wang and Huang 1999); however, prior 

versions did not include shale gas. Furthermore, the well field infrastructure, construction fuel 

consumption, and well completion emissions were not included for the conventional NG 

pathway. For this study, these previously excluded activities were incorporated into GREET’s 

conventional gas pathway, and the shale gas pathway was developed and added to GREET. 

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2 METHODS 

The assumptions used to update the conventional gas pathway and develop the shale gas 

life-cycle inventory are described here. The U.S. Environmental Protection Agency (EPA) 

methodology for determining the greenhouse gas (GHG) emissions from the natural gas sector as 

part of the U.S. GHG Inventory, a significant data source for our work, is also summarized. 

Finally, this section contains detailed explanations of the methodology and assumptions in 

Howarth et al. (2011) for understanding the differences between the results of those researchers 

and our own. 

2.1 Life-Cycle Analysis Approach 

In our life-cycle analysis (LCA) of shale gas and conventional NG, we include fuel 

recovery, fuel processing, and fuel use, as well as transportation and distribution of fuels. In 

addition, we include the establishment of infrastructure, such as gas well drilling and completion. 

Figure 2 below shows the particular stages included in our study for both shale gas and 

conventional NG life cycles. 

FIGURE 2 System Boundary for Shale and Conventional NG Pathways 

Functional units for LCA directly affect the meaning of LCA results. In our study, we 

included three functional units: per-megajoule (MJ) of fuel burned (for comparison with 

Howarth et al. 2011), per-kilowatt-hour (kWh) of electricity produced by targeting electricity 

generation as an end use of shale gas and natural gas, and per-mile driven for transportation 

services by targeting the transportation sector for expanded gas use. The latter two functional 

units take into account efficiencies of energy conversion into energy services, as well as 

efficiencies and emissions of energy production. There are large variations and uncertainties in 

data for critical LCA stages in our study. Therefore, to systematically address uncertainties, we 

developed statistical distribution functions for the key parameters in each pathway in order to 

perform stochastic modeling of the pathways evaluated in this study. 

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2.2 Data Sources and Key Parameters Associated with Natural Gas Recovery 

The EPA develops the U.S. GHG emissions inventory annually. This effort accumulates 

large amounts of GHG data as EPA develops methodologies to estimate emissions for different 

sectors, including the oil, coal, and NG sectors. The EPA methodologies and data are widely 

used by others, including by us, for performing GHG analyses of specific energy systems. A 

summary of key emission factors considered in the recovery of natural gas is provided in 

Table 1. Each stage and the assumptions behind its associated emissions are described in 

Sections 2.2.4 and 2.2.5. 

TABLE 1 Selected Activity Factors for the Recovery of Natural Gas 

Sample Emission Sources for Shale and Conventional Gas 

Stage Unless Otherwise Noted 

Well Completions  Drill out methane (CH4) venting 

 Flow back CH4 venting (shale only) 

Workovers  CH4 venting 

Liquid Unloading  CH4 venting (conventional only) 

Miscellaneous Venting  Field separation equipment 

 Gathering compressors 

 Normal operations 

 Condensate collection 

 Compressor venting 

 Upsets 

Flaring  Carbon dioxide (CO2) emissions 

In its most recent inventory estimation, EPA made major methodological changes to how 

it analyzes the total CH4 emissions of the U.S. NG system (EPA 2011). While EPA’s CH4 

emission factors for the U.S. NG system are based primarily on a joint study by the gas industry 

and EPA (Harrison et al. 1996), the EPA updates activity factors, such as length of the 

U.S. pipeline network and number of producing gas wells, on an annual basis. EPA also makes 

minor adjustments to emission factors where appropriate and includes additional CH4 sources 

when data become available. We note that in its 2011 inventory estimation, EPA made a 

significant upward adjustment of CH4 emissions from the U.S. NG system, such that total CH4 

emissions more than doubled from levels used in the previous inventory. Table 2 presents the 

changes to selected EPA emission factors. 

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TABLE 2 Comparison of Changes to Selected EPA Emissions Factors (EPA 2010b) 

Emissions Source 

Previous 

Emissions Factor 

Revised 

Emissions Factor Units 

Well venting for liquids 

unloading 

1.02 11 NG metric tons/year-well 

Gas venting during well completions 

Conventional well 0.02 0.71 NG metric tons/yearcompletion 

Conventional well 0.05 0.05 NG metric tons/year-workover 

Unconventional well 0.05 177 NG metric tons/year-workover 

Centrifugal compressor 

wet seal degassing 

venting 

0 233 NG metric tons/yearcompressor 

Unconventional well 0.02 177 NG metric tons/yearcompletion 

Gas venting during well workovers 

Notes: Conversion factor of 0.01926 metric tons = 1 Mcf. Units correct mislabeling of metric tons of NG with 

metric tons of CH4 in EPA (2010b). 

The underlying reasons for these adjustments are explained in Sections 2.2.4 and 2.2.5. 

Burdens associated with NG recovery as part of the EPA GHG inventory and those burdens 

outside of the GHG inventory are detailed in the following subsections. 

Table 3 summarizes the key parameters that are discussed in the following subsections 

and are included in the natural gas pathways. 

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TABLE 3 Key Parameters for Natural Gas Simulation in GREET (mean values with ranges in 

parentheses) 

Parameter Units Conventional Shale Source 

Well Lifetime 

Bulk Gas Methane 

Content 

Years 

% 

30 

85 (69–95) 

30 

80 (40–97) 

Industry and 

Argonne 

Assumption 

Hanle 2011 

Production over Well 

Lifetime (estimated 

ultimate recovery) 

Well Completion and 

Workovers (venting) 

NG million cubic 

feet 

Metric ton NG 

per completion or 

workover 

1,550 

(1,320–1,780) 

0.71 

3,460 

(1,600–5,320) 

177 

(13.5–385) 

Conv: EIA 2011b; 

Shale: Chesapeake 

Energy 2010 

EPA 2010b 

CH4 Reductions for 

Completion or 

Workovers 

% 0 41 (37–70) EPA 2011; 

EPA 2010a 

Number of Workovers 

per well lifetime 

Workovers per 

lifetime 2 2 EPA 2010b 

Liquid Unloadings 

(venting) 

Liquid Unloading 

Events 

CH4 Reductions for 

Liquid Unloadings 

Metric ton NG 

per unloading 

Unloadings per 

year 

% 

0.86

31 (11–51) 

12 (8–15) 

0 

0 

0 

EPA 2010b 

EPA 2010b 

EPA 2011; 

EPA 2010a 

Wells Requiring 

Unloadings 

Well Equipment 

(leakage and venting) 

CH4 Reductions for 

Well Equipment 

Well Equipment (CO2 

from flaring) 

Well Equipment (CO2 

from venting) 

Processing (leakage 

and venting) 

Processing (CO2 from 

venting) 

Transmission and 

Storage (leakage and 

venting) 

Distribution (leakage 

and venting)a 

% 

Grams CH4 per 

million Btu NG 

% 

Grams CO2 per 

million Btu NG 

Grams CO2 per 

million Btu NG 

CH4: % of NG 

produced 

Grams CO2 per 

million Btu NG 

CH4: % of NG 

produced 

CH4: % of NG 

produced 

41.3 

209 

(114–303) 

28 (18–37) 

454 

(369–538) 

41

0.15 

(0.06–0.23) 

878 

(615–1140) 

0.39 

(0.2–0.58) 

0.28 

(0.09–0.47) 

0 

209 

(114–303) 

28 (18–37) 

454 

(369–538) 

41 

0.15 

(0.06–0.23) 

878 

(615–1140) 

0.39 

(0.2–0.58) 

0.28 

(0.09–0.47) 

EPA 2010b 

GAO 2010; 

EPA 2011 

EPA 2011; 

EPA 2010a 

GAO 2010; 

EPA 2011 

EPA 2011 

EPA 2011 

EPA 2011 

EPA 2011 

EPA 2011 

a	 Distribution accounts for leakage and venting from terminals to refueling stations. It does not apply to major 

industrial users, such as electricity generators. 

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2.2.1 Estimated Ultimate Recovery 

Given that the EPA GHG inventory emissions from NG well completions and liquid 

unloadings are estimated on a per-well basis, it was necessary to determine the estimated 

ultimate recovery (EUR) of gas from a well to amortize these periodic emissions over the total 

amount of natural gas produced. For shale gas wells, a range was developed for EURs according 

to the per-well weighted average of four major plays: Marcellus, Barnett, Haynesville, and 

Fayetteville. The high estimates were based upon industry average–targeted EURs 

(Mantell 2010b). The low estimates were based upon a review of emerging shale resources 

developed by INTEK, Inc., for the EIA (INTEK 2011). The INTEK analysis captured the 

variability in EUR within a play by evaluating the EUR for the best area, the average area, and 

the below-average area in a play. INTEK further presented EURs for active portions and 

undeveloped portions of major plays, and generally, the active portions of the play had larger 

EURs than did the undeveloped areas. Comparing the EURs with the industry average–targeted 

EURs, the active EURs reported in INTEK were similar, with the exception of the Marcellus 

play. While the active reported EURs reported by INTEK were lower for the Marcellus than the 

industry average–targeted EUR, the industry average–targeted EUR was contained within the 

range of EURs presented for the best, average, and below-average EURs for the Marcellusdeveloped area. We averaged the high and low values to estimate our Base Case shale gas well 

EUR of 3.5 billion cubic feet (Bcf), as shown in Table 4. 

TABLE 4 Lifetime Production Estimates According to Play (INTEK 2011; Mantell 2010b) 

Low EUR Estimates (Bcf) High EUR Estimates (Bcf) 

Barnett 1.4 3.0 

Marcellus 1.4 5.2 

Fayetteville 1.7 2.6 

Haynesville 3.5 6.5 

Per-Well Weighted Average 1.6 5.3 

The estimates in Table 4 are for the bulk gas, which is a mixture containing methane in 

addition to other gases such as ethane, propane, carbon dioxide, and nitrogen. 

For the conventional NG EUR, we assumed an average production rate over the lifetime 

of the well according to EIA production data and EPA well compositional makeup, recognizing 

that production rates typically decline over time, to estimate a Base Case EUR of 1.0 Bcf 

(EPA 2011, EIA 2011b). Our estimate of conventional EUR is comparable to a value from an 

analysis of Texas wells prior to large-scale shale gas production (Swindell 2001). It should be 

noted when comparing the EURs that shale gas recovery typically uses horizontal drilling to 

access large rock volumes, whereas conventional gas recovery often uses multiple vertical wells, 

each accessing a smaller rock volume. To account for these differences and enable comparison, 

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the analysis evaluates impacts on a per-million-Btu (mmBtu) basis. In addition, in the case of 

conventional gas, it may be that the highly productive wells have ceased production and modern 

wells return relatively less gas, as shown by the fall in the EUR for Texas over the years 

(Swindell 2001). As the large-scale recovery of NG from shale plays is a relatively new pursuit, 

the EUR may not reflect future conditions when the technologies that support large-scale shale 

gas recovery are more mature. For emissions associated with processing, transmission, storage, 

and distribution, we based our emissions calculations on total production of shale gas (SG) and 

NG as we did not need to differentiate by gas source (EIA 2011b). 

2.2.2 Well Design, Drilling, and Construction 

The drilling phase of the NG life cycle requires the use of drill rigs, fuel, and materials, 

including the casing, cement, liners, mud constituents, and water. Water is used during the well 

construction stage in drilling fluids, for cementing the casing in place, and for hydraulically 

fracturing the well in the case of shale gas. For the purposes of our analysis, the horizontal shale 

gas wells were based on designs for the 4H, 5H, and 6H Carol Baker wells and modified 

according to the depth of the shale play (Range Resources 2011a–c). For horizontal drilling, a 

well is drilled down to the depth of the play and turned approximately 90 degrees to run laterally 

(horizontally) through the play for 2,000 to 6,500 feet (ft). Vertical wells draw from a much 

smaller area within a play. The conventional NG scenario assumed a vertical well design, which 

was based upon a design from the Mississippi Smackover and adjusted to the national average 

depth of gas wells (Bourgoyne et al. 1991; EIA 2011b). Because of the long lateral reach of 

horizontal wells, they can access more of the play, which typically increases production on a perwell basis. 

The total volume of drilling muds, or fluids, used to lubricate and cool the drill bit, 

maintain downhole hydrostatic pressure, and convey drill cuttings from the bottom of the hole to 

the surface depends upon the volume of the borehole and the physical and chemical properties of 

the formation. The ratio of barrels (bbl) of drilling mud to bbl of annular void used in this 

assessment was 5:1 according to data obtained from the literature (EPA 1993). The material 

inventory assumes use of water-based fluids for the Barnett and Haynesville plays. Analysis of 

the Marcellus and Fayetteville plays assumes use of air drilling through the upper portion of the 

well to a depth of 392 ft and water drilling below that depth (GWPC and ALL 2009). For the 

water-based drilling muds, a ratio of 1 bbl of water to 1 bbl of drilling mud was assumed. The 

composition of the mud was adapted from Mansure (2010) to provide the required drilling fluid 

properties. The dominant material — by several orders of magnitude — was bentonite; as a 

result, the other materials were ignored for this study. 

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To determine fuel consumption, the following assumptions were made: 

 The drill rig operates with a 2,000-horsepower (hp) engine, 

 The engine consumes diesel fuel at a rate of 0.06 gallon (gal)/hp/hour (h), and 

 The drill rig runs at 45% of capacity. 

These assumptions are similar to those reported by Tester et al. (2006), EPA (2004a), and 

Radback Energy (2009). By assuming that the drill rig operates 24 hours per day and then using 

an average number of days drilled from Overbey et al. (1992) and extrapolating to the various 

plays according to depth, the total diesel fuel required for drilling can be determined. Although 

diesel fuel requirements for on-site activities and transportation burdens for diesel and water 

were included in the inventory, the transportation burdens of materials (e.g. mud, cement, steel) 

were not included. The summary of materials, water, and fuel used to drill and construct the 

horizontal wells is presented in Table 5. 

TABLE 5 Material Requirements for Drilling and Constructing a Typical Well by Play (units are 

in metric tons per well unless otherwise indicated) 

Shale Gas Conventional Gas 

Well Drilling Barnett Marcellus Fayetteville Haynesville 

Low 

Estimate 

High 

Estimate 

Steel 163 145 114 226 40 55 

Portland Cement 267 239 187 371 84 115 

Gilsonite 

(asphaltite) 9 8 7 13 13 18 

Diesel Fuel 

(gallons) 61,768 55,080 43,041 85,845 17,820 24,300 

Bentonite 61.38 44 42.99 68.23 19.64 26.88 

Soda Ash 1.06 0.7 0.74 1.13 0.34 0.46 

Gelex 0.04 - 0.03 - 0.01 0.02 

Polypac 1.60 1.4 1.12 2.22 0.53 0.72 

Xanthum Gum 0.81 0.7 0.57 1.13 0.27 0.37 

Water (throughput 269,693 199,924 188,827 311,457 85,107 116,514 in gallons per well)a 

a Water volumes do not account for water associated with hydraulic fracturing activities. 

2.2.3 Hydraulic Fracturing and Management of Flowback Water 

Because of the low permeabilities of shale formations, which limit the flow of NG within 

the formation, producers hydraulically fracture the formation to enable the flow of NG. This 

outcome is accomplished by pumping fracture fluid at a predetermined rate and pressure 

sufficient to create fractures in the target formation. The fracture fluid for shale formations is 

typically water based and consists of proppants, sand, or similarly sized engineered particles that 

maintain fracture openings once they have been established and the pumping of fracture fluid has 

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ceased. Although we included the transportation and management burdens for water and 

flowback from hydraulic fracturing activities, we did not include the production and 

transportation burdens of proppants and other chemicals, because the small amounts of 

consumption involved would affect the results only minimally. 

For this analysis, values for fracturing (or frac) fluid constituents were based upon 

fraccing data made available by Range Resources, which released frac fluid information for 

several of its Marcellus wells (Range Resources 2010a–c). Large volumes of water are required 

for drilling and fraccing activities. Typical volumes depend on the characteristics of the shale 

and are provided in Table 6. 

TABLE 6 Typical Range of Water Requirements Per Well for Fraccing 

Activities by Shale Play (GWPC & ALL 2009, Mantell 2010b) 

Shale Play Typical Range of Frac Water Input per Well (gallons) 

Barnett 2,300,000–3,800,000 

Marcellus 3,800,000–5,500,000 

Fayetteville 2,900,000–4,200,000 

Haynesville 2,700,000–5,000,000 

The total water input varies according to geology and drilling practices, with air drilling 

commonly practiced in the Marcellus and Fayetteville plays. While the constituents of a frac job 

will vary according to site conditions, the average concentrations of these constituents were 

extrapolated to other shale plays according to typical water use for a relatively similar frac in 

each play. The estimated components and amounts for frac jobs in the Marcellus are presented in 

Table 7. 

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TABLE 7 Estimated Fraccing Fluid Components According to Average 

Values from Selected Marcellus Wells (Range Resources 2010a–c) 

Per Well Amount Unit 

Water 4,614,556 gal 

Sand 6,049,200 pounds 

Friction Reducer (polyacrylamide, mineral oil) 1,843 gal 

Antimicrobial Agent 1,316 gal 

Glutaraldehyde 163 gal 

n-alkyl dimethyl benzyl ammonium chloride 27 gal 

Ethanol 3 gal 

4,4-Dimethyloxazolidine 723 gal 

3,4,4-Trimethyloxazolodine 47 gal 

2-Amino-2-methyl-1-propanol 10 gal 

Formaldehyde Amine 4 gal 

Scale Inhibitor 454 gal 

Sodium hydroxide 17 gal 

Ethylene glycol 270 gal 

Perforation Cleanup 409 gal 

37% HCl 409 gal 

Methanol 13 gal 

Propargyl Alcohol 0.5 gal 

Because of the relatively small amounts of chemicals per mmBtu, the life-cycle energy 

and emissions burdens of the proppants and components of fracturing fluids were not included. 

However, the energy and emissions burdens associated with fraccing and managing the flowback 

water were included. 

Another component of fracturing a well is the management of flowback water. Flowback 

water is the water that is produced from the well immediately after hydraulically fracturing the 

well and before gas production commences. Outside of the Marcellus, flowback water is 

collected and typically disposed of through underground injection. Within the Marcellus region, 

however, flowback water is collected and typically reused in fraccing activities. Using average 

frac fluid volumes per well and assuming that water was transported both on- and off-site via 

truck, we determined the electricity and fuel requirements associated with hydraulic fracturing 

activities. 

For the Marcellus, 95% of flowback was assumed to be recycled because of the longdistance transport requirements to dispose of the fluid via injection wells. For the other plays, 

where injection wells are located nearby, recycle rates were assumed to be 20% of flowback for 

the Barnett and Fayetteville plays and 0% for the Haynesville play (Mantell 2010a). The total 

volume of recycled fluid depends on the fraction of frac fluid that flows back up the well after 

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hydraulic fracturing activities, which varies considerably among the different shale plays. For 

example, while the majority of the plays considered do not recover all of the hydraulic fracturing 

fluid during the flowback period, the Barnett shale typically yields a larger volume of flowback 

water than was used during hydraulic fracturing activities. Flowback rates, recycle rates, and 

distances required to transport and manage flowback water were based upon input from industry 

experts. The flowback fractions and the typical distances between water source, well site, and 

injection disposal well are summarized for each play in Table 8. The transportation burden 

associated with hauling recycled flowback to a well site is accounted for only as an input to 

avoid double counting as the burden associated with removal would be allocated to another well 

as input. 

TABLE 8 Assumptions in Determining the Transportation and Management of Hydraulic 

Fracturing Fluids (Gaudlip et al. 2008; Mantell 2010a; Stinson 2008) 

Parameter Barnett Marcellus Fayetteville Haynesville 

Water volume per truck (gal/truck) 5,500 3,400a

 5,500 5,500 

Distance to transport freshwater to site (miles) 5 10 15 15 

Distance to transport recycled fluid to site 

(miles) 2 5 5 5 

Distance to transport fluid to disposal well 

(miles) 10 50 20 10 

Flowback fraction 2.75 0.2 0.25 0.9 

Recycled fraction 0.20 0.95 0.20 0.00 

a Volume reported in Gaudlip et al. (2008). The smaller volume is an artifact of the terrain, which limits vehicle 

size in the Marcellus. 

Diesel fuel consumption was determined according to the typical distances that water is 

trucked and accounted for trips to and from the well site. Distances will vary according to well 

location. It was assumed that truck fuel consumption was 5 miles per gallon (mpg) for a loaded 

truck and 7 mpg for an unloaded truck, as determined from Delorme et al. (2009) and Davis et al. 

(2010), which is consistent with GREET. To determine the electricity consumed by the pumps 

associated with injection for disposal, injection well parameters from Nakles et al. (1992) were 

used to determine pump energy as described in Geankoplis (1993) and the following equation: 

1000௘ߟߟ ൌ ሻܹ݇ሺ ݐݑ݌݅݊ ݎ݁ݓ݋݌ ݅ܿݎݐ݈݁ܿܧ ݃݉ܪ

where H is the head of the pump in meters of fluid, g is the gravimetric constant 9.8 m/s2, m is 

the flow rate in kg/s, ߟ is the fractional efficiency, ߟ ௘is the electric motor drive efficiency, and 

1000 is the conversion factor of W/kW. Table 9 presents both diesel fuel consumption and 

electricity consumption according to shale play. 

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TABLE 9 Fuel and Energy Requirements for the Management of Frac Fluid 

Hydraulic Fracturing Fluid Management 

Volume per Frac Job Diesel Fuel Electricity Consumption 

Shale Play (gal/well) Consumption (gal/well) (kWh/well) 

Barnett 3,019,000 4,771 94,887 

Marcellus 4,615,000 4,444 659 

Fayetteville 3,523,000 4,063 10,066 

Haynesville 3,803,000 5,689 48,891 

2.2.4 Well Completions 

After the well is drilled and constructed, the bottom of the hole must be prepared, 

production tubing must be run through the well, and the well must be perforated or hydraulically 

fractured as required. All of these steps are part of the well completion process. As shale gas 

wells require hydraulic fracturing, the fugitive methane emissions associated with completion of 

wells for shale are different from those estimated for conventional NG. Previous inventories 

were based on data for conventional wells only, and those emissions were assumed to be flared. 

To estimate emissions from conventional well completions, we are using the updated emission 

factor from the EPA of 0.71 metric tons NG per conventional well completion (EPA 2010b). We 

divided this emission factor by our estimate of EUR. As mentioned above, the EUR was 

determined by dividing the conventional gas production by the total number of producing 

conventional gas wells in 2009 (EPA 2011, EIA 2011b). The total number of conventional gas 

producing wells was determined by multiplying the total number of wells reported by the EIA by 

the percent of conventional gas wells to total gas wells reported by the EPA (EPA 2011; 

EIA 2011b). To convert bulk gas to methane, we assumed a distribution according to natural gas 

production by state and average methane concentration (EIA 2010b; GTI 2001). The weighted 

average methane content derived by using this approach was determined to be 84.6%. 

For conventional well completion emissions, Howarth et al. (2011) also cite the EPA 

(EPA 2010b). Howarth et al. (2011) converted to an NG emission factor assuming 78.8% 

methane content. The NG emission factor was then multiplied by the total well count in 2007 

and divided by the total NG produced in 2007 to arrive at the percent of methane produced over 

the well life cycle. It is likely that the differences in approach and production year account for 

the differences in emissions between our study and Howarth et al. (2011). Nonetheless, 

conventional well emissions are significantly smaller than are those for unconventional wells. 

The shale gas well completion emissions in this analysis are based on several EPA 

sources (EPA 2011, 2010a, 2010b). The estimate of CH4 vented during shale gas well 

completions accounts for the additional time that venting occurs after hydraulic fracturing as the 

flowback water is collected prior to the commencement of gas production. The emission factors 

used by EPA are based on data from reduced emission completions (RECs) (EPA 2004b, 2007). 

RECs are practices and technologies that when implemented can reduce the amount of methane 

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emitted during a well completion. From these data, which include both tight sand and shale 

plays, EPA calculated unmitigated completion emissions ranging from 700 to 20,000 thousand 

cubic feet (Mcf) of natural gas with an average of 9,175 Mcf or 177 metric tons of natural gas 

per unconventional completion (or 139 metric tons of methane per unconventional completion, 

assuming 78.8% methane content). Periodically during the productive life of a well, the well will 

need to be cleaned, have new production tubing installed, and will potentially be re-perforated or 

refractured. This maintenance process is referred to as a well workover. The same emission 

factor used for a well completion is assumed for a shale gas well workover, as the well would 

likely require additional hydraulic fracturing every 10 years (EPA 2010b). 

This approach may lead to overestimation because wells without REC equipment will 

typically conduct flowback for a shorter time period than do REC wells. In contrast, the 

equipment used for RECs allows operators to carry out flowback for a longer period of time, 

permitting improved debris removal and well flow. Overestimation may also result from 

estimating flowback emissions according to initial production rates. This approach was evident 

in some Natural Gas STAR data as reported in Howarth et al. (2011) (Samuels 2010; 

Bracken 2008; EPA 2007, 2004b). Initial production rates are calculated following hydraulic 

fracturing and flowback. After hydraulic fracturing of a well, the flowback initially brings up 

mostly sand and frac fluids. As the sand and water are removed, the gas concentration increases. 

When the well builds to a high enough pressure, venting ceases and the gas can be directed to the 

gathering lines. Therefore, using the initial production rate for the entire flowback period 

significantly overestimates completion emissions. Howarth et al. (2011)’s high-end estimate for 

the range of completion emissions for the Haynesville Shale relied on initial production 

estimates from an industry report that highlighted several high-volume wells (Eckhardt et al. 

2009). These researchers assumed that flowback would last 10 days as they did not have a 

reference for this play, and when multiplied by the initial production rate of approximately 

24,000 Mcf/day for these high-producing wells, the resulting emissions might be overestimated. 

Emission factors associated with shale gas completions require further development to reduce the 

uncertainties involved. Accounting for flaring and reduction practices is discussed in 

Section 2.2.7, Methane Reductions from Natural Gas Recovery. 

2.2.5 Liquid Unloadings and Miscellaneous Leakage and Venting 

In addition to emissions associated with well completions and workovers, fugitive 

methane emissions also occur at the wellsite from liquid unloading activities, leaks, and 

miscellaneous venting. Liquid unloading is the process of removing liquids that gradually build 

up and block flow in wet gas wells. EPA significantly adjusted the emissions associated with 

liquid unloading as a result of data reported by the Natural Gas STAR Program (EPA 2010a). 

The unmitigated emission factor is based upon fluid equilibrium calculations and Natural Gas 

STAR Program data for two basins (EPA 2004b, 2006). EPA assumes that liquid unloadings 

apply only to conventional wells. Although the assumption is reasonable given that shale gas is 

typically a dry gas, some shale formations such as the Antrim and New Albany do produce water 

and may require liquid unloadings. EPA estimated the unmitigated emission factor by 

calculating: (1) the amount of gas needed to blow out the liquid, which is a function of well 

depth, casing diameter, and shut-in pressure; and (2) the amount of gas vented after the liquid has 

14
 
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been blown out by using annual recovery data reported by operators utilizing automated plunger 

lift systems to remove liquids and capture gas. The number of unloadings for the two basins were 

11 and 51, respectively, with an average of 31 unloadings per well per year. In addition, the 

original inventory work by Harrison et al. (1996) assumed that 41.3% of conventional wells 

require liquid unloading. As a result, the emission factor reported by EPA is 11 metric tons of 

NG per year per well, which suggests that 26.7 metric tons of NG are released per year per every 

well that requires liquid unloadings. Our unloading estimates are significantly higher than are 

those of Howarth et al. (2011), who estimated liquid unloadings from GAO (2010). The 

U.S. Government Accountability Office (GAO) estimates were based on 2006 estimates from the 

Western Regional Air Partnership, which determined emissions in part from surveying operators, 

as well as on 2008 estimates from EPA, which were developed prior to the methodological 

change. 

The frequency of liquid unloadings will depend on the age of the well and will likely vary 

both between and within plays. According to EPA, liquid unloadings account for 50% of the 

unmitigated emissions for the NG production sector, and therefore, the absence of reliable data 

on the frequency of unloadings and their emissions creates a large degree of uncertainty for the 

conventional NG pathway (EPA 2010b). Thus, researchers — taking both variation in the 

frequency of liquid unloadings and the significant uncertainty stemming from limited testing into 

account — should further examine these emission factors. 

For both shale and conventional wells, methane emissions can result from various on-site 

equipment (and practices), such as pneumatic devices, condensate tanks, and gathering 

compressors. Assuming that similar equipment would be located on site at both shale gas and 

natural gas wells and would perform similarly, we estimated the unmitigated emissions from 

these sources using two approaches. The first approach used EPA emissions for 2005 through 

2009 and normalized them according to gross NG production data for the same time period. This 

approach estimated unmitigated emissions at 114 grams of methane per million Btu (lower 

heating value) of NG (EPA 2010b, 2011). The second approach relied on a report by GAO, 

which included EPA 2008 emissions data for federal onshore activities, and the Bureau of Land 

Management’s 2008 estimate for federal onshore production of 3,106 Bcf, from which we 

derived an emission factor of 303 grams of CH4 per million Btu of NG (GAO 2010; BLM 2010). 

We used these data points as the range for our distribution and the mean value as our Base Case. 

In addition to estimating methane emissions from well equipment and practices, we 

examined CO2 flaring and venting. According to data in EPA (2011), we estimated that flaring 

would emit 369 grams of CO2 per million Btu of NG, while according to data provided in GAO 

(2010), we estimated that flaring would emit 538 grams of CO2 per million Btu of NG. As NG 

also contains CO2, vented emissions were estimated to be roughly 41 grams of CO2 per million 

Btu of NG (EPA 2011). 

Howarth et al. (2011) developed their methane emissions for well equipment leakage and 

venting from GAO and calculated an emissions leakage range between 0.3% (for best available 

technology) and 1.9% of NG produced (GAO 2010). Howarth et al. (2011) did not provide 

estimates of CO2 emissions for flaring or venting. 

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2.2.6 Recovery Pipeline to Compression Station 

Once the shale gas is produced, it is directed from the wells to the main pipeline — 

similar to the process used in conventional gas production. For both conventional and shale gas, 

four wells were assumed per square mile, although that number can vary according to site 

(GWPC and ALL 2009). Schedule 40 stainless steel was assumed for the pipeline for inventory 

purposes. Gas is collected (assumedly in a 4-inch diameter pipe) at the well pad and is then 

conveyed via an 8-inch diameter pipe to a gathering station that collects gas produced within a 

4- to 6-mile radius. From the gathering station, the gas is conveyed into a 12-inch diameter pipe 

toward local compression stations, where the gas is processed and pressurized prior to delivery to 

the main pipeline. The compression station typically processes gas produced within a 10- to 

20-mile radius. To determine the material and fuel allocations of the pipelines per mmBtu, the 

inventory was first allocated per well and then converted to mmBtu according to the EUR. 

Several steps are involved in constructing and installing a pipeline. Although the steps 

can be run in parallel to reduce the total amount of time spent at a site, diesel-consuming 

equipment is required for each stage and can include hydraulic excavators or pipelayers. As 

GREET already contains inventory and emissions associated with the main trunkline 

(Wang 1999; He and Wang 2000), this analysis focused on the installation of the smaller 

pipelines that feed into the main line at the compression stations. Therefore, it was assumed that 

small-sized equipment would be used and that the engines would have a maximum of 120 hp 

according to equipment specifications (Caterpillar 2010). It was also assumed that the equipment 

would run at 70% capacity during an 8-hour work day, or at 23% capacity for 24 hours. 

Assuming that a diesel engine consumes fuel at a rate of 0.06 gal/hp/h (Radback Energy 2009), 

the fuel required to run one piece of equipment for pipeline construction at specified capacity 

and horsepower levels results in a daily fuel consumption rate of 90.5 gal/day (340.9 liters 

[L]/day) according to the following equation: 

Fuel Consumption [gal/day] = 0.23[h/h] × 120[hp] × 0.06[gal/hp−h] × 24[h/day] 

Pipelines are typically installed in a series of steps. After a right of way is established, 

excavators create a trench. Sections of pipe are laid along the length of the trench. At this point, 

the pipe is bent and welded to form a continuous piece and conform to the contours of the trench. 

After being treated with a protective coating, the pipe is lowered into the trench and then 

backfilled with soil (Kern River Gas Transmission Company 2010). For the 2- to 4-inch diameter 

pipe, it was assumed that approximately 1,000–2,000 ft could be installed per day. For 6-inch 

diameter pipe, it is assumed that approximately 1,000 ft of pipe could be installed per day. For 

12-inch diameter pipe, approximately 500 ft of pipe/day could be installed. These assumptions 

were used to calculate the total number of days required to install the pipelines from the wells to 

the gathering stations and to the compressor station. Table 10 presents the material and fuel 

requirements for installing the pipelines from the wellhead to the compression station. 

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TABLE 10 Average Material and Energy Requirements for Pipeline per mmBtu of Natural Gas 

Conventional 

Shale Estimate per mmBtu Estimate per mmBtu 

Low High 

Inventory Barnett Marcellus Fayetteville Haynesville Estimate Estimate 

Steel (Mg/mmBtu) 7.09E-05 4.17E-05 7.30E-05 2.99E-05 6.92E-04 1.50E-04 

Diesel Fuel 

(gal/mmBtu) 2.68E-04 1.58E-04 2.76E-04 1.13E-04 2.62E-03 5.68E-04 

2.2.7 Methane Reductions from Natural Gas Recovery 

One impetus for the EPA to revise the GHG emissions estimates was the realization that 

the methane reductions reported by the Natural Gas STAR Program were larger than the total 

unmitigated emissions calculated using its previous methodology. In our analysis, the 

unmitigated emission factors for each activity associated with natural gas recovery were adjusted 

to represent real-world conditions according to EPA aggregated emissions reduction data. 

However, although the aggregated emissions data from EPA (2011) show reductions from both 

the Natural Gas STAR Program and the National Emission Standards and Hazardous Air 

Pollutants (NESHAP) regulations, details were not provided on emission reductions by activity. 

Therefore, we examined data from the Natural Gas STAR Program to estimate emissions 

reductions for each activity (EPA 2010a). 

We grouped the recovery sector technologies listed in Natural Gas STAR documentation 

and their respective CH4 reductions into three categories: (1) unconventional well completions, 

(2) conventional liquid unloadings, and (3) well equipment venting and leakage. As the Natural 

Gas STAR Program only provides partially aggregated results to protect confidential business 

information, the reduction data lack details. Through background information provided by EPA, 

we separated most of the reductions from RECs and technologies based on liquid unloading and 

thus were able to estimate the equipment emissions (Hanle 2011). For example, as a category, 

RECS had the largest emissions savings reported by Natural Gas STAR Program partners, with 

savings ranging from 33% to 56% of the reductions from the production sector for each year 

from 2005 to 2009. 

The NESHAP regulations set standards to reduce emissions of hazardous air pollutants, 

although these regulations have a secondary benefit in reducing methane emissions. In EPA 

GHG inventory estimates, emissions from flaring are included under NESHAP reductions, as 

states such as Wyoming require that vented emissions from well completions and workovers be 

flared. EPA assumed that in states without these regulations, such as Texas, Oklahoma, and 

New Mexico, no flaring would occur. EPA estimated that approximately 51% of the total 

number of unconventional wells in Texas, Oklahoma, New Mexico, and Wyoming were located 

in Wyoming and required flaring (EPA 2010b). It was then extrapolated that 51% of all 

unconventional completions are required to be flared in the United States. 

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The EPA conducts quality assurance and control checks of the Natural Gas STAR 

reductions prior to incorporating them into its inventory estimates. While the emissions 

reductions from Natural Gas STAR and NESHAP are considerable at approximately 30% of the 

unmitigated emissions in 2009, detailed information is limited. To address some of the 

uncertainty in these estimates, we developed distribution functions for these reductions. For shale 

completions, most of the uncertainty was attributable to flaring assumptions: thus, our lowreduction reduction scenario assumed only reductions from the Natural Gas STAR program 

(38%); while our Base Case assumed a small amount of flaring based on the number of wells in 

Wyoming, along with the Natural Gas STAR reductions (41%); and finally, our high-reduction 

reduction scenario assumed the same amount of flaring as the EPA did, along with Natural Gas 

STAR reductions (70%) (EPA 2010a). For conventional wells, there was significant uncertainty 

associated with liquid unloadings as the Natural Gas STAR accounting practices do not report 

emissions reduction projects that have exceeded an agency-prescribed sunsetting period, even 

though those emissions are still being reduced in practice. Therefore, we developed a lowreduction reduction scenario for liquid unloadings based on reported Natural Gas STAR 

reductions (8%) and a high-reduction reduction scenario where we adjusted for the sunsetting 

period (15%), while our Base Case is the average of those two. For the third category, well 

equipment, which applies to both shale gas and conventional gas recovery, we developed a lowreduction reduction scenario based on Natural Gas STAR and NESHAP reductions (18%) and a 

high-reduction reduction scenario in which we adjusted for the sunsetting period (37%), while 

our Base Case is the average of those two. 

2.3 Data for Natural Gas Processing, Transmission, Storage, and Distribution 

Downstream from the recovery stage, NG passes through a processing stage in which 

undesirable elements of raw gas (such as NG liquids) are removed. The processed NG enters the 

transmission and storage (T&S) stage, in which NG is moved long distances through highpressure pipelines. Compressor station facilities, where turbines and compressors force the gas 

through the large-diameter pipes, dot the transmission pipeline network. At times, NG is 

delivered directly from the transmission network to industrial customers. Alternatively, the gas 

may be stored underground or liquefied and stored in aboveground tanks. Before residential and 

commercial customers access the gas, its pressure is reduced and it travels through the 

distribution network of low-pressure pipes that are often underground. Pipeline construction for 

distribution is not included, as it is assumed to exist already and would be identical for shale gas 

and conventional natural gas. Table 11 details key activities that result in fugitive methane 

emissions from natural gas processing, transmission and storage, and distribution. 

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TABLE 11 Selected Activity Factors for the Processing, Transmission and Storage, and 

Distribution Sectors 

Sector Sample Activity Data 

Processing  Processing plants 

 Centrifugal compressors 

 Acid gas removal vents (CO2 source) 

 Blowdowns/venting 

Transmission and Storage	  Reciprocating and centrifugal compressors 

 Dehydrator vents 

 Pneumatic devices 

Distribution  Miles of mains and services by material (iron, steel, plastic, 

copper) 

 Metering and regulating stations 

 Residential customer meters 

For natural gas processing, transmission and storage, and distribution, it is assumed that 

shale gas would be treated in a manner similar to that of conventional natural gas. As a result, the 

existing pathway in GREET, as described in Wang et al. (2007), Brinkman et al. (2005), Wang 

(1999), and Wang and Huang (1999), was used, and the GHG emissions associated with these 

stages were updated, as appropriate. To calculate methane leakage emissions from NG 

processing, T&S, and distribution sectors, we divided the average methane emissions from these 

sectors by the average production of NG for this same time period (EPA 2011; EIA 2011b). If 

NG exports were significant during this time period, this approach could underestimate 

emissions in the T&S and distribution sectors. Exports, however, were 4% of production in 2009, 

the year with the greatest volume of NG exports in the period between 2005 and 2009 

(EIA 2011b). The use of NG production volume in the calculation of the emission factors is 

therefore reasonable. 

We also examined vented CO2 emissions from acid gas removal (AGR) in the processing 

sector. These emissions account for about 50% of the total GHG emissions from the processing 

sector (EPA 2010b). The results for these sectors include CH4 emission factor distributions based 

on the uncertainties provided in Harrison et al. (1996). For the low and high AGR vent emission 

factors, we assumed an uncertainty of plus or minus 30% based on EPA’s discussion (2010b). 

Significant differences exist between our analysis of these sectors and that of 

Howarth et al. (2011). For the processing sector, Howarth et al. (2011) used the mean emissions 

facility-level gas-processing emission factor for fugitive CH4 of 0.19% as provided in the 

American Petroleum Institute’s (API’s) Compendium to estimate processing sector emissions 

(Shires et al. 2009). API developed a range of 0% to 0.19% for these emissions, with the lower 

bound of zero representing wells that produce pipeline-ready gas that needs no processing. API 

did not explicitly estimate CO2 emissions from AGR) vents in their analysis. Shires et al. (2009) 

use data from the 1990s, such as the 1993 volume of total gas processed; they state that the 

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uncertainty associated with the reported emission factor is plus or minus 82.2%, placing the 

emission factor between 0.03% and 0.35% of total gas processed. 

In their analysis, Howarth et al. (2011) did not distinguish between the T&S and 

distribution sectors, whereas our analysis breaks out emission factors for these sectors. Table 12 

illustrates that the derivation of the low value (1.4%) from the analysis by Howarth et al. (2011) 

is an estimate of emissions from the Russian NG transmission and distribution network 

(Lelieveld et al. 2005). The estimate of NG leakage in the Russian T&S and distribution sectors 

is likely an overestimate of emissions for these sectors in the United States for several reasons. 

First, an examination of emissions suggests that the activity and emission factors for the two 

systems will be different. Specifically, compressor emissions in the Russian T&S sector indicate 

that the emission factor for this sector in Lelieveld et al. (2005) is likely too high to be 

representative of T&S sector emissions in the United States. Second, the estimate of leakage 

from the distribution sector was based on outdated U.S. emissions rates from 2002 and earlier. In 

the United States, this sector has seen emissions decrease significantly by 13% between 1990 

and 2009 with the adoption of lower-emitting technology, such as plastic piping (EPA 2011). 

TABLE 12 Derivation of Lelieveld et al.’s (2005) Estimate of Natural Gas Losses during 

Transmission and Distribution in Russia 

Methane Loss 

(% of Total 

Natural Gas Sector Throughput) Data Source 

Domestic Russian transmission 0.7 (0.4–1.6) Field measurements in Russia 

Domestic Russian distribution 0.5–0.8 Assumed that the percentage of produced NG 

leaked in the Russian and U.S. distribution 

networks would be roughly equivalent 

Domestic Russian gas spills at 

wells 

0.1 ± 0.04 Re-evaluation of data from Dedikov et al. (1999) 

Total 1.4 (1.0–2.5) 

The high value (3.6%) that Howarth et al. (2011) cite for the T&S and distribution 

sectors is the average of two years’ estimates of lost and unaccounted for gas (LUG) in Texas 

(Percival 2010). LUG is an accounting term for the difference between the volume of gas 

produced and that sold. Percival (2010) points out drawbacks to using LUG as an estimate of 

leaked NG. First, differences in the accuracy of measurements between wellhead and process 

plant devices, compounded by changes in volume due to ambient temperature variations, 

introduce discrepancies between measured volumes of produced and processed gas. In addition, 

when NG is processed, high-value liquids and impurities are separated, further widening the gap 

between the volumes of gas measured at the wellhead and post processing. Finally, LUG 

calculations can include NG produced at the wellhead that is used as a process fuel in equipment 

used for gathering and processing, thereby depleting the amount of gas that ultimately is sold. 

Howarth et al. (2011) assert that these factors (except gas theft) are randomly distributed and 

therefore will not yield a high or low bias in estimates of NG leakage. However, others assert 

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that LUG will consistently overestimate actual emissions to the atmosphere (Percival 2010; 

Kirchgessner et al. 1997). In summary, LUG is not a reliable means of quantifying NG leakage 

in the T&S and distribution sectors. 

2.4 GREET Life-Cycle Analysis 

Since 1996, Argonne National Laboratory has been developing and using the GREET 

model to examine the life-cycle energy and emissions effects of different transportation fuels and 

advanced vehicle technologies (Argonne 2011; see also http://greet.es.anl.gov/main). To explore 

energy and emissions issues associated with shale gas and conventional gas, we used the GREET 

model to develop a shale gas pathway, to estimate up-to-date life-cycle GHG emissions of shale 

and conventional gas energy options, and to quantify the uncertainties in the estimated GHG 

emissions of both technologies. 

With the parametric assumptions incorporated into the GREET model, we produced lifecycle GHG emissions for the energy pathways with three functional units. With the distribution 

functions as described in Section 2.2, we used GREET’s stochastic modeling capability to 

generate results with distributions. 

2.4.1 Treatment of Emissions from Early 1990s Natural Gas Systems to Current Systems 

Key emission factors for NG systems in previous GREET versions were based on 

Harrison et al. (1996), which examined the NG system found in the early 1990s. As NG use in 

the United States expands, certain subsystems (such as NG wells and storage facilities) expand, 

but other subsystems (such as NG transmission and distribution pipelines) may remain at the 

same size and extent. To address this situation, previous input parameters to GREET implicitly 

assumed that only production and processing capacity would be added to the NG system to 

handle the increased demand between early 1990s and now. The T&S and distribution sectors, 

however, had extra capacity and would not be expanded. As a result, emission factors from 

Harrison et al. (1996) were modified prior to use in GREET, as outlined in Table 13. 

TABLE 13 Comparison of Current GREET Emissions Factors with Harrison et al. (1996) 

CH4 Emissions: Percent of 

Volumetric Natural Gas Produced New GREET Values 

Sector 

Harrison et al. 

(1996) 

Existing 

GREET Values 

Conventional 

NG Shale Gas 

Production

Processing 

Transmission 

Distribution

 0.38 

0.16 

0.53 

0.35 

0.35 

0.15 

0.27 

0.18 

1.93 

0.15 

0.39 

0.28 

1.19 

0.15 

0.39 

0.28 

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As presented in Section 2.2, we updated CH4 emission factors for NG, and as a result (see 

Table 13), the emission factors for the T&S and distribution sectors are markedly higher than 

they are in previous GREET analyses. 

2.4.2 End-Use Efficiencies 

We included the end-use efficiencies for both power plants and vehicles to estimate the 

life-cycle GHG impacts of the fuels in specific applications. For NG power plants, we estimated 

that conventional NG boilers are 33% efficient and NG combined cycle (NGCC) power plants 

are 47% efficient, according to data calculated from EIA Form-906 “Power Plant Report” 

(EIA undated). For coal power plants, efficiencies were estimated at 34% for conventional 

pulverized coal boilers and 42% for supercritical boilers, according to IEA (2006). 

For a passenger car, we assumed a fuel economy of 29 miles per gallon gasolineequivalent (mpgge). We assumed that a compressed natural gas (CNG) car with similar 

performance would have a fuel economy penalty of 5% (on an mpgge basis) primarily because 

of the weight penalty of onboard CNG storage cylinders. We developed a distribution function 

for the relative fuel economy of the CNG car as compared to the gasoline car. For the high 

estimate, it was assumed that the CNG car would have the same fuel economy. The low estimate 

assumed that the CNG car would have a 10% reduction as compared to the gasoline car. 

Several studies have examined the fuel consumption of NG and diesel transit buses. On 

average, CNG-fueled transit buses have a fuel economy 20% lower than that of diesel-fueled 

buses (Adams and Home 2010; Barnitt and Chandler 2006; Chandler et al. 2006). This finding is 

attributable to the low thermal efficiency of a spark-ignited engine when operating at low speed 

and load as compared to a compression-ignition diesel engine (Barnitt and Chandler 2006). 

However, it has been argued that, because of equipment and strategies employed to meet the 

EPA’s 2010 heavy-duty engine emissions standards, the fuel efficiency benefit of diesel buses 

has been reduced. According to Cummins-Westport (in Adams and Home 2010), the 8.1-liter 

ISL G NG engine can either match an equivalent diesel engine in fuel economy or have a fuel 

economy that is 10% lower depending on the duty cycle. For our analysis, CNG transit buses 

would have a 20% reduction in fuel economy for our low estimate and a 10% reduction in fuel 

economy for our high estimate. The mean value was assumed to be our Base Case. A summary 

of our end-use efficiency assumptions is shown in Table 14. 

22
 
 

 

 

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TABLE 14 End-Use Efficiency Assumptions for GREET Simulations (mean values with ranges in 

parentheses) 

Power Plant Units Values Sources 

NGCC efficiency % 47 

(39–55) 

Average of 2007 and 2008 data based on 

Form EIA 906, “Power Plant Report” 

NG boiler efficiency % 33.1 

(33.0–33.5) 

Brinkman et al. 2005 

Supercritical Coal 

Boiler efficiency 

% 41.5 

(39.0–44.0) 

IEA 2006 

Subcritical Coal % 34.1 Brinkman et al. 2005 

Boiler efficiency (33.5–34.4) 

Vehicles 

Gasoline passenger 

car – fuel economy 

Miles per gallon – 

gasoline equivalent 

29 

(23–32) 

Honda Civic LX, MY 2007-11; assumed 

high 10% better, low 20%; based on 

driving behavior (DOE 2011). 

CNG passenger car 

– fuel economy 

Ratio of gasoline 

car 

0.95 

(0.9–1.0) 

Mid-range value based on GREET 5% 

reduction; high value assumed fuel 

economy can reach same level as gasoline 

(Wang 1999); low value based on 1990s 

CNG vehicle models. 

Diesel transit bus – 

fuel economy 

Miles per gallon – 

diesel equivalent 

3.5 

(3.0–3.7) 

Mid-range value is based on Davis et al. 

(2010). Transportation Energy Data Book 

Ed. 29 assumed that high value is 5% 

better, low value 15% worse; based on 

driving behavior and vehicle 

technologies. 

CNG transit bus – Ratio of diesel bus 0.85 Low value is with 20% reduction based 

fuel economy (0.80–0.90) on numerous transit bus studies; high 

value is based on Adams and Home 

(2010); mid-range value is average of 

high and low. 

2.4.3 Greenhouse Gas Global Warming Potentials 

Global warming potential (GWP) provides a simple measure to compare the relative 

radiative effects of various GHG emissions. The index is defined as the cumulative radiative 

forcing between the time a unit of gas is emitted and a given time horizon, expressed relative to 

that for CO2. When comparing the emissions impacts of different fuels, researchers must choose 

a time frame for comparison. The Intergovernmental Panel on Climate Change (IPCC) calculates 

GWPs for multiple time horizons, such as 20-, 100-, and 500-year time frames. The IPCC 

recommends using GWPs for a 100-year time horizon when calculating GHG emissions for 

evaluating various climate change mitigation policies. When using a 20-year timeframe, the 

effects of methane are amplified as it has a relatively short perturbation lifetime (12 years), 

whereas CO2 can last in the air for a long time. Howarth et al. (2011) use results from a recent 

study by Shindell et al. (2009), whereas our analysis relies on the IPCC’s current, published 

23
 
 

Final ANL/ESD/11-11
 

December 2011
 

results (IPCC 2007). Table 15 presents the GWPs that we used in comparison to those used by 

Howarth et al. (2011). 

TABLE 15 Global Warming Potentials of Greenhouse Gases 

100-Year GWPs 20-Year GWPs 

CO2 CH4 N2O CO2 CH4 N2O Source

GREET 

Howarth et al. 2011 

1 25 298 1 72 289 IPCC 2007 

1 33 Not used 1 105 Not used Shindell et al. 2009 

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3 RESULTS AND DISCUSSION 

The life-cycle GHG emissions of shale and conventional NG were evaluated according to 

three functional units —grams of CO2 equivalent per kilowatt-hour produced (gCO2e/kWh), 

grams of CO2 equivalent per vehicle mile driven (gCO2e/mile), and grams of CO2 equivalent per 

megajoule produced (gCO2e/MJ) — over two GWP time horizons (i.e., 100-year and 20-year 

horizons). The results are presented and the impact of parameter uncertainty for both natural gas 

pathways is discussed. 

3.1 GHG Emissions by End Use 

When compared to the coal pathway, NG pathways show life-cycle GHG benefits on an 

average basis for the 100-year time horizon, as shown in Figure 3. When using GWPs for the 

20-year time horizon, the emission benefits for the NG pathways are diminished (also shown in 

Figure 3). Only for the worst case of an NG boiler under a 20-year GWP time horizon do the 

emissions approach (in the case of shale) or exceed (in the case of conventional NG) a 

supercritical coal power plant. 

FIGURE 3 Life-Cycle GHG Emissions per kWh of Electricity Produced. Two time horizons — 

100-year and 20-year — are considered (note: WTW = well to wheels, NGCC = 

natural gas combined cycle). 

100 20 100 20 100 20 100 20 100 20 100 20

Boiler NGCC Boiler NGCC Boiler Supercritical

Infrastructure

Fuel Production

Fuel Combustion

Conv. Gas Shale Gas Coal

WTW GHG Emissions (gCO2e/kWh)

1,400

1,200

1,000

800

600

400

200

0

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Final ANL/ESD/11-11
 

December 2011
 

Figure 4 illustrates emissions in gCO2e per mile for passenger cars. Considering a 

100-year GWP horizon, there is no statistically significant difference in well-to-wheels (WTW) 

life-cycle GHG emissions among fuels on a vehicle-mile-traveled (VMT) basis. The GHG 

emissions for CNG cars are 3% lower for NG and 8% lower for SG than are those of gasoline 

cars in the 100-year time horizon. When considering a 20-year GWP horizon, however, 

conventional NG has a greater WTW life-cycle GHG impact than does gasoline. The emissions 

of CNG cars are higher by 25% for conventional NG and by 12% for shale NG, on average. 

0

100

200

300

400

500

600

100 20 100 20 100 20

Gasoline Conv. Gas Shale Gas

WTW GHG Emissions (gCO2e/mi)

Infrastructure

Fuel Production

Vehicle Operation

FIGURE 4 Well-to-Wheels Life-Cycle GHG Emissions per VMT – 

Passenger Car. Two time horizons — 100-year and 20-year — 

are considered. 

The GHG emissions per VMT for transit buses are illustrated in Figure 5. The emissions 

per VMT for CNG transit buses are not statistically different from those of diesel buses with a 

100-year GWP horizon. However, when considering a 20-year GWP horizon, CNG buses emit 

significantly more GHGs than do their petroleum-fueled counterparts, with emissions that are 

34% higher for conventional NG and 20% higher for shale NG. To reduce GHG emissions, CNG 

buses will need to exceed our Base Case fuel economy assumptions. 

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Final ANL/ESD/11-11
 

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0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

5,500

100 20 100 20 100 20

Diesel Conv. Gas Shale Gas

WTW GHG Emissions (gCO2e/mi)

Infrastructure

Fuel Production

Vehicle Operation

FIGURE 5 Well-to-Wheels Life-Cycle GHG Emissions per VMT – 

Transit Bus. Two time horizons — 100-year and 20-year — 

are considered. 

3.2 Detailed Breakdown of GHG Emissions for Fuel Pathways 

Figure 6 presents the results for the NG pathways in terms of gCO2e/MJ. For both NG 

pathways, the emissions from direct fuel combustion are the largest contributors to life-cycle 

GHG emissions. Shale gas shows fewer GHG emissions than does conventional NG per MJ. 

This result is mainly attributable to the large CH4 emissions associated with liquid unloadings 

and the lower EUR for a conventional NG well. The further breakdown of upstream and 

infrastructure emissions for the pathways enables examination of the relative importance of CH4 

leakage and CO2 venting and flaring. For NG pathways, CH4 venting and leakage during NG 

recovery operations are the largest upstream GHG emissions source. Liquid unloadings are a key 

factor for conventional NG, whereas completion and workover emissions are significant for 

shale gas. GHG emissions associated with materials and fuels for infrastructure are almost 

negligible in terms of the life-cycle emissions. The chart also shows the relative uncertainties for 

each pathway based on our stochastic simulations. 

27
 
   

   

   

   

   

   

   

Final ANL/ESD/11-11
 

December 2011
 

0

20

40

60

80

100

120

100 20 100 20

GHG Emissions (g CO2e/MJ)

Infrastructure

Fuel Production

Fuel Combustion

Conventional Gas Shale Gas

Fuel Production

Unloadings CH4 Leak

Recovery: CO2 Leak

Recovery: CH4 Leak

Recovery: Combustion

Refining: CO2 Leak

Refining: CH4 Leak

Refining: Combustion

T&D: CH4 Leak

T&D: Combustion

Infrastructure

Infrastructure: CH4 Leak

Infrastructure: Combustion

FIGURE 6 Life-Cycle GHG Emissions per MJ of Fuel Produced and Combusted for Both 

100-year and 20-year GWPs 

3.3 Examination of Uncertainty of Key Parameters with Respect to Life-Cycle Emissions

 With CH4 venting and leakage during NG recovery operations serving as the largest 

upstream GHG emissions sources and with liquid unloadings and EUR significantly contributing 

to differences in conventional and shale NG emissions, a sensitivity analysis was performed to 

examine the effect of the uncertainty of key parameters on the life-cycle emissions of NG and 

SG. The following “tornado” charts (Figure 7 and Figure 8) present results of our sensitivity 

analysis of key parameters affecting life-cycle GHG results for NG and SG pathways. 

Considering only the conventional NG tornado charts, it is clear that CH4 venting during 

liquid unloadings contributes the most uncertainty to our GHG emissions estimates under both 

time horizons. The next most significant parameter is CH4 venting from well equipment. The 

large uncertainty is attributable to the wide range in the number of unloadings required for 

conventional wells and the subsequent emissions resulting from this activity. As the GWP of 

CH4 is much larger under the 20-year time horizon than it is under the 100-year time horizon, the 

impact of the CH4 venting during liquid unloading is greater under the former. 

The shale gas tornado charts show trends similar to those of the conventional NG tornado 

charts outside of liquid unloadings as it is assumed the unloadings are not to be required for shale 

28
 
     

     

     

   

   

         

   

   

     

     

     

     

     

     

   

   

   

         

     

   

   

   

     

     

     

         

   

Final ANL/ESD/11-11
 

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gas wells (EPA 2010). The other major difference between the two pathways (as previously 

noted) is that the completion and workover emissions associated with shale gas wells are much 

more significant than are similar emissions associated with conventional NG. However, 

completion and workover emissions have only moderate impacts on the uncertainty of life-cycle 

emissions, although the impacts are more pronounced under the 20-year time horizon. Under 

both time horizons, uncertainties in CH4 venting from well equipment shows the largest impact 

on life-cycle GHG emissions for the shale NG pathway as the difference between the estimates 

from EPA (2011) and GAO (2010) are significant. 

‐6% ‐4% ‐2% 0% 2% 4% 6%

CH4 Venting: Liq. Unloadings

CH4 Venting: Well Equip.

EUR of Conv. Well

NG Recovery Eff.

NG Processing Eff.

CH4 Content in Raw Conv. Gas

CH4 Venting: Distribution

CH4 Venting: T&S

CH4 Reduction: Well Equip.

CH4 Venting: NG Processing

CO2 Venting: AGR Equip.

CH4 Reduction: Liq. Unloadings

NG Flaring

EUR of Shale Well

CH4 Venting: Well Equip.

CH4 Venting: Workover

NG Recovery Eff.

NG Processing Eff.

CH4 Content in Raw Shale Gas

CH4 Venting: Well Completion

CH4 Venting: Distribution

CH4 Venting: T&S

CH4 Reductions: Completion/Workover

CH4 Reduction: Well Equip.

CH4 Venting: NG Processing

CO2 Venting: AGR Equip.

NG Flaring

Percent Change of Life‐Cycle GHG Emissions

Low Value in

Range

High Value

in Range

Conventional Gas

Shale Gas

FIGURE 7 Sensitivity Analysis Results for Shale and NG Pathways 

(100-Year Time Horizon) 

29
 
     

     

     

         

   

   

   

   

     

     

     

     

     

     

   

         

     

   

   

   

   

   

     

     

     

         

Final ANL/ESD/11-11
 

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‐12% ‐8% ‐4% 0% 4% 8% 12%

CH4 Venting: Liq. Unloadings

CH4 Venting: Well Equip.

EUR of Conv. Well

CH4 Content in Raw Conv. Gas

CH4 Venting: Distribution

CH4 Venting: T&S

NG Recovery Eff.

NG Processing Eff.

CH4 Reduction: Well Equip.

CH4 Venting: NG Processing

CH4 Reduction: Liq. Unloadings

CO2 Venting: AGR Equip.

NG Flaring

EUR of Shale Well

CH4 Venting: Well Equip.

CH4 Venting: Workover

CH4 Content in Raw Shale Gas

CH4 Venting: Well Completion

CH4 Venting: Distribution

CH4 Venting: T&S

CH4 Reductions: Completion/Workover

NG Recovery Eff.

NG Processing Eff.

CH4 Reduction: Well Equip.

CH4 Venting: NG Processing

CO2 Venting: AGR Equip.

NG Flaring

Percent Change of Life‐Cycle GHG Emissions

Low Value

in Range

High Value

in Range

Conventional Gas

Shale Gas

FIGURE 8 Sensitivity Analysis Results for Shale and NG Pathways 

(20-Year Time Horizon) 

30
 
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December 2011
 

4 SUMMARY AND IMPLICATIONS 

The analysis demonstrates that upstream CH4 leakage and venting are key contributors to 

the upstream emissions of the NG pathway. These emissions can significantly reduce the benefits 

of producing NG as compared to coal or petroleum. The fact that only limited data have been 

available for several key issues has resulted in significant changes to EPA’s GHG inventory 

estimation and some erroneous conclusions. More reliable and diverse data will aid the 

evaluation of the role of natural gas in the U.S. energy supply. 

Specifically, for conventional wells, the volume of gas vented during liquid unloadings 

needs to be calculated for the various technologies that are employed on-site to remove liquids. 

Furthermore, a survey of the prevalence of each technology would provide much greater 

certainty to these emissions estimates. Such a survey could also examine what percentage of 

conventional NG and shale wells require liquid unloadings, as not all wells undergo this process. 

Given that the number of unloadings required over the lifetime of the well causes significant 

uncertainty, this factor should be examined in detail. These data could help researchers 

differentiate the unloading practices in different plays or geologic formations, as well as in 

different wells within the same play. A temporal evaluation to determine the number of 

unloadings required as a function of the age of the well would also provide relevant information 

when trying to create an inventory of these emissions. Flaring practices should also be examined 

for liquid unloading operations by both state regulations and industry practices. 

For shale gas wells, the volume of gas vented during completions and workovers needs to 

be examined with and without RECs. This examination will improve understanding of the 

quantity of fraccing fluids and natural gas that are produced during the flowback period and the 

variability of the volume of fluid and gas that flow during that time. In addition to emissions 

associated with completions and workovers, the estimated number of workovers required during 

the expected lifetime of a shale gas well needs further examination. The decision to rework a 

well will be based on a number of factors that affect the economics of the well, including the age 

of the well, the expected improvement in NG production after workover, and the wellhead price 

of NG. Moreover, greater transparency is needed to aid in identifying the percentage of wells 

that are employing emissions-reduction practices. This identification includes completions and 

workovers implementing REC technologies and flaring practices for wells both with and without 

RECs. Such information could be gathered by examining state regulations and industry practices 

and could provide greater certainty regarding the emissions from shale gas. Finally, as the NG 

industry gains more experience with SG production through the lifetime of the well, the accuracy 

of EUR projections will hopefully improve. 

Environmental management and GHG emissions reduction strategies need to be 

exercised in large-scale operation for shale and conventional NG to reduce the environmental 

and energy burdens associated with producing these fuels. The voluntary partnership of the 

natural gas industry and EPA under the Natural Gas STAR Program has helped reduce CH4 

emissions; however, further efforts could be undertaken to extend the application of emissionsreduction projects across the industry, develop new mitigation measures, and address the 

remaining environmental issues associated with natural gas production and transmission. 

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