Final ANL/ESD/11-11

December 2011

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 Asso ciated with Natural Gas Recovery

.................. 4

2.2.1 Estimated Ultimat e 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 Miscella neous 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, Tran smission, 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

iiiFinal ANL/ESD/11-11

December 2011

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 El ectricity 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-y ear — are considered.

............................................................ 26

5 Well-to-Wheels Life-Cycle GHG Emissions per VMT – Transit Bus. Two time horizons — 100-year and 20-y ear — 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 Sele cted 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 We ll for Fraccing Activities by Shale Play

....... 10

7 Estimated Fraccing Fluid Components Accord ing to Average Values from Selected

Marcellus Wells

............................................................................................................... ....... 11

8 Assumptions in Determining the Trans portation 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 fo r Pipeline per mmBtu of Natural Gas

.......... 17

11 Selected Activity Factors for the Pr ocessing, 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

ivFinal ANL/ESD/11-11

December 2011

TABLES (CONT.)

14 End-Use Efficiency Assumptions for GREET Simulations

................................................... 23

15 Global Warming Potentials of Greenhouse Gases

................................................................. 24

vFinal ANL/ESD/11-11

December 2011

ACKNOWLEDGMENTS

This study was supported by the Vehicle Tech nologies 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 Ke vin Stork and Linda Bluestein from the Vehicle Technologies Program for their s upport. 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 infrastruc ture. Finally, we are grat eful to Lisa Hanle,

U.S. Environmental Protection Agency, and Dougl as Sechler, ICF Intern ational, for providing additional information on the critical assumpti ons of EPA’s revised emissions estimates.

viFinal ANL/ESD/11-11

December 2011

LIFE-CYCLE ANALYSIS OF SHALE GAS AND NATURAL GAS

Corrie E. Clark, Jeongwoo Han, Andrew Bu rnham, Jennifer B. Dunn, Michael Wang Center for Transportation Rese arch, Argonne National Laboratory

December 2011

ABSTRACT

The technologies and practices that have en abled 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 distri bution of shale gas a nd conventional natural gas, we have estimated up-to-d ate, life-cycle greenhouse gas em issions. In addition, we have developed distribution functions fo r key parameters in each path way 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 emissi ons are indeed lower than conventional gas emissions. This life-cycle analysis provides insigh t into the critical stages in the natural gas industry where emissions occur and where oppor tunities exist to reduce the greenhouse gas footprint of natural gas.

viiFinal ANL/ESD/11-11

December 2011

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 Standa rds 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

viiiL Final ANL/ESD/11-11

December 2011

Units of Measure

bbl barrel(s)

Bcf billion cubic feet Btu British thermal unit(s)

ft foot, feet

gal gallon(s) gCO 2 e/MJ grams of carbon dioxide equivalent per megajoule gCO 2 e/kWh grams of carbon dioxide equivalent pe r kilowatt-hour of el ectricity generated gCO 2 e/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)

ixFinal ANL/ESD/11-11

December 2011

This page intentionally left blank.

xFinal ANL/ESD/11-11

December 2011

1 INTRODUCTION

Production of natural gas (NG) from shale fo rmations 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 ch allenges to large-scale development. Largescale shale gas production started in the Barn ett 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, includi ng the Haynesville, Marcellus, and Fayetteville shales. The development of this resource has gene rated 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 contribut ed 16% of the U.S. na tural gas supply. By 2035, it is estimated that its contribution will incr ease to 47% of total U.S. production of natural gas, with this anticipated growth in production ra ising the natural gas cont ribution 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 sh ale gas in the United States. Shal es that are considered to be important include the Marcellus, Haynesville, Fayetteville, and Barnett. Other important plays include the Antrim, Eagle Ford, Ne w Albany, and Woodford (Figure 1).

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

1Final ANL/ESD/11-11

December 2011

With significant potential growth in unconventional gas production, the life-cycle impacts of natural gas may change. “Unconventi onal 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 emissi ons associated with producing, processing, transporting, and consuming natural gas produced from conventional natu ral gas resources and shale gas resources. Argonne’s GREET (Greenh ouse gases, Regulated Emissions, and Energy use in Transportation) model had previous ly developed the conventional gas pathway (Wang et al. 2007; Brinkman et al. 2005; Wa ng 1999; Wang and Huang 1999); however, prior versions did not include shale ga s. Furthermore, the well field in frastructure, construction fuel consumption, and well completion emissions we re not included fo r the conventional NG pathway. For this study, these previously exclude d activities were inco rporated into GREET’s conventional gas pathway, and the shale gas pathway was developed and added to GREET.

2Final ANL/ESD/11-11

December 2011

2 METHODS

The assumptions used to update the conven tional 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 th e methodology and assumptions in

Howarth et al

. (2011) for understanding the differences be tween the results of those researchers

and our own.

2.1 Life-Cycle Analysis Approach

In our life-cycle analysis (LCA) of shal e 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 infrastr ucture, 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 functiona l units: per-megajoule (MJ) of fu el burned (for comparison with Howarth et al. 2011), per-kilowatt- hour (kWh) of electricity produ ced by targeting electricity generation as an end use of shale gas and natura l gas, and per-mile driven for transportation services by targeting the transportation sector for expanded gas use. Th e 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 va riations and uncertainties in data for critical LCA stages in our study. Therefor e, 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.

3Final ANL/ESD/11-11

December 2011

2.2 Data Sources and Key Parameters Asso ciated 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 met hodologies to estimate emissions for different sectors, including the oil, coal, and NG sector s. 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 natura l 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 (CH 4 ) venting

 Flow back CH 4 venting (shale only)

Workovers  CH 4 venting

Liquid Unloading  CH 4 venting (conventional only)

Miscellaneous Venting  Field separation equipment

 Gathering compressors

 Normal operations

 Condensate collection

 Compressor venting

 Upsets

Flaring  Carbon dioxide (CO 2 ) emissions

In its most recent inventory estimation, EP A made major methodological changes to how it analyzes the total CH 4 emissions of the U.S. NG system (EPA 2011). While EPA’s CH 4 emission factors for the U.S. NG system are ba sed primarily on a joint study by the gas industry and EPA (Harrison et al. 1996), the EPA updates activity factor s, such as length of the

U.S. pipeline network and number of producing ga s wells, on an annual basis. EPA also makes minor adjustments to emission factors where appropriate and includes additional CH 4 sources when data become available. We note that in its 2011 inventory estimation, EPA made a significant upward adjustment of CH 4 emissions from the U.S. NG system, such that total CH 4 emissions more than doubled from levels used in the previous inventor y. Table 2 presents the changes to selected EPA emission factors.

4Final ANL/ESD/11-11

December 2011

TABLE 2 Comparison of Changes to Sel ected 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/yea r -well

Gas venting during well completions

Conventional well 0.02 0.71 NG metric tons/yea r

completion

Conventional well 0.05 0.05 NG metric tons/yea r -workove r

Unconventional well 0.05 177 NG metric tons/yea r -workove r Centrifugal compressor wet seal degassing venting 0 233 NG metric tons/yea r

compressor Unconventional well 0.02 177 NG metric tons/yea r

completion

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 CH 4 in EPA (2010b).

The underlying reasons for these adjustment s 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 de tailed 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.

5Final ANL/ESD/11-11

December 2011

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

CH 4 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

CH 4 Reductions for Liquid Unloadings Metric ton NG per unloading Unloadings per

yea r

% 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)

CH 4 Reductions for Well Equipment
Well Equipment (CO 2 from flaring)
Well Equipment (CO 2 from venting)
Processing (leakage and venting)
Processing (CO 2 from venting)

Transmission and Storage (leakage and venting) Distribution (leakage and venting) a %

Grams CH 4 per million Btu NG

%

Grams CO 2 per million Btu NG

Grams CO 2 per million Btu NG

CH 4 : % of NG produced

Grams CO 2 per million Btu NG

CH 4 : % of NG produced

CH 4 : % 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 term inals to refueling stations. It does not apply to major industrial users, such as electricity generators.

6Final ANL/ESD/11-11

December 2011

2.2.1 Estimated Ultimate Recovery

Given that the EPA GHG i nventory 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 we lls, a range was developed for EURs according to the per-well weighted average of four majo r plays: Marcellus, Barnett, Haynesville, and Fayetteville. The high estimates were ba sed upon industry average–targeted EURs (Mantell 2010b). The low estimates were base d 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 th e EUR for the best area, the average area, and the below-average area in a play. INTEK furt her presented EURs for active portions and undeveloped portions of major play s, 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 av erage–targeted EUR was contained within the range of EURs presented for the best, averag e, and below-average EURs for the Marcellusdeveloped area. We averaged the high and low va lues to estimate our Base Case shale gas well EUR of 3.5 billion cubic feet (B cf), as shown in Table 4.

TABLE 4 Lifetime Production Estimates A ccording 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 ga s, 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 ti me, 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 produc tion (Swindell 2001). It should be noted when comparing the EURs that shale gas r ecovery 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,

7Final ANL/ESD/11-11

December 2011

the analysis evaluates impacts on a per-million-Bt u (mmBtu) basis. In addition, in the case of conventional gas, it may be that the highly pr oductive 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 th e technologies that su pport large-scale shale gas recovery are more mature. For emissions asso ciated with processing, transmission, storage, and distribution, we based our emissions calcula tions 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 lif e cycle requires the use of dri ll rigs, fuel, and materials, including the casing, cement, liner s, mud constituents, and water. Water is used during the well construction stage in drilling fluids, for cemen ting 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). Vertic al wells draw from a much smaller area within a play. The conventional NG s cenario 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 lo ng lateral reach of horizontal wells, they can access more of the pl ay, 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 th e bottom of the hole to the surface depends upon the volume of the borehol e and the physical and chemical properties of the formation. The ratio of barrels (bbl) of dri lling mud to bbl of annular void used in this assessment was 5:1 according to data obtained fr om 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 pl ays 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 Mansur e (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.

8Final ANL/ESD/11-11

December 2011

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 (g al)/hp/hour (h), and

 The drill rig runs at 45% of capacity.

These assumptions are similar to those repor ted by Tester et al. (2006), EPA (2004a), and Radback Energy (2009). By assuming that the dr ill rig operates 24 hours per day and then using an average number of days drilled from Overbey et al. (1992) and extrap olating 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 transportatio n burdens for diesel and water were included in the inventory, the transportati on 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 Co nstructing 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 Cemen t 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 asso ciated with hydraulic fracturing activities.

2.2.3 Hydraulic Fracturing and Man agement of Flowback Water

Because of the low permeabilities of shale fo rmations, 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 flui d at a predetermined rate and pressure

sufficient to create fractures in the target formation. The fractur e fluid for shale formations is typically water based and consists of proppants, sa nd, or similarly sized engineered particles that maintain fracture openings once they have been established and the pumping of fracture fluid has

9Final ANL/ESD/11-11

December 2011

ceased. Although we included the transportati on and management burdens for water and flowback from hydraulic fract uring activities, we did not include the production and transportation burdens of proppants and othe r 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 Marcellu s wells (Range Resources 2010a–c). La rge volumes of water are required for drilling and fraccing activities. Typical volu mes depend on the characteristics of the shale and are provided in Table 6.

TABLE 6 Typical Range of Water Re quirements 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 ge ology and drilling practices, with air drilling commonly practiced in the Marcellus and Fayettevi lle plays. While the constituents of a frac job will vary according to site condi tions, the average concentrations of these constituents were extrapolated to other shale plays according to ty pical 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.

10Final ANL/ESD/11-11

December 2011

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 com ponents of fracturing flui ds were not included. However, the energy and emissions burdens asso ciated with fraccing and managing the flowback

water were included.

Another component of fracturi ng a well is the management of flowback water. Flowback water is the water that is pr oduced from the well immediately af ter hydraulically fracturing the well and before gas production commences. Outs ide of the Marcellus, flowback water is collected and typically dispos ed of through underground injecti on. Within the Marcellus region, however, flowback water is coll ected and typically reused in fraccing activities. Using average frac fluid volumes per well and assuming that wate r 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 ra tes were assumed to be 20% of flowback for the Barnett and Fayetteville plays and 0% for the Haynesville play (M antell 2010a). The total volume of recycled fluid depends on the fraction of frac fluid that flows back up the well after

11Final ANL/ESD/11-11

December 2011

hydraulic fracturing activities, which varies cons iderably among the different shale plays. For example, while the majority of the plays consid ered do not recover all of the hydraulic fracturing fluid during the flowback period, th e Barnett shale typically yields a larger volume of flowback water than was used during hydrau lic fracturing activities. Flowb ack 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 Tran sportation 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 3,400 a 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 accord ing to the typical dist ances 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 tr uck fuel consumption was 5 mile s per gallon (mpg) for a loaded truck and 7 mpg for an unloaded truck, as determin ed from Delorme et al. (2009) and Davis et al. (2010), which is consistent with GREET. To de termine 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:

݃݉ܪ

ൌ ሻ ܹ݇ ሺ ݐݑ݌݅݊ ݎ݁ݓ݋݌ ݅ܿݎݐ݈݁ܿܧ ߟߟ ௘ 1000

where H is the head of the pump in meters of fluid, g is the gravimetric constant 9.8 m/s 2 , 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.

12Final ANL/ESD/11-11

December 2011

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, a nd the well must be perforated or hydraulically fractured as required. All of thes e steps are part of the well completion process. As shale gas wells require hydraulic fracturing, the fugitive meth ane emissions associated with completion of

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

were based on data for conventi onal 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 conventiona l well completion (EPA 2010b). We

divided this emission factor by our estimate of EUR. As me ntioned above, the EUR was determined by dividing the conventional gas production by the tota l number of producing conventional gas wells in 2009 (EPA 2011, EIA 2011b). The total number of conventional gas producing wells was determined by multiplying th e total number of wells reported by the EIA by the percent of conventional gas wells to tota l 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 con centration (EIA 2010b; GTI 2001). The weighted average methane content derived by using th is approach was determined to be 84.6%.

For conventional well comple tion emissions, Howarth et al

. (2011) also cite the EPA (EPA 2010b). Howarth et al. ( 2011) converted to an NG emi ssion factor assuming 78.8%

methane content. The NG emission factor wa s then multiplied by the total well count in 2007 and divided by the total NG produced in 2007 to arri ve at the percent of methane produced over the well life cycle. It is likely that the differences in approa ch and production year account for the differences in emissions between our study and Howarth et al. (2011). Nonetheless, conventional well emissions are significantly sma ller 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 CH 4 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 comm encement 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

13Final ANL/ESD/11-11

December 2011

emitted during a well completion. From these da ta, which include both tight sand and shale plays, EPA calculated unmitigated completi on 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 du ring the productive life of a well, the well will need to be cleaned, have new production tubing inst alled, and will pot entially be re-perforated or refractured. This maintenance process is referre d to as a well workover. The same emission factor used for a well completion is assumed fo r a shale gas well workov er, as the well would likely require additional hydraulic fr acturing 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 init ial production rates. This approach was evident in some Natural Gas STAR data as reporte d in Howarth et al. (2011) (Samuels 2010; Bracken 2008; EPA 2007, 2004b). Initial producti on 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 wate r are removed, the gas concentration increases. When the well builds to a high enou gh pressure, venting ceases and th e gas can be directed to the gathering lines. Therefore, using the initial pr oduction rate for the entire flowback period significantly overestimates comple tion 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 w ould 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 comple tions require further development to reduce the uncertainties involved. Accounting for flari ng 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 wellsit e from liquid unloading activities, leaks, and miscellaneous venting. Liquid unloa ding is the process of removing liquids that gradually build up and block flow in wet gas we lls. 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 fl uid 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 reasona ble 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 li quid, which is a function of well depth, casing diameter, and shut-in pressure; and (2) the amount of gas vented after the liquid has

14Final ANL/ESD/11-11

December 2011

been blown out by using annual recovery data reported by operators util izing 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 Ha rrison et al. (1996) assumed th at 41.3% of conventional wells require liquid unloading. As a resu lt, 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 unloadi ngs. Our unloading estimates are significantly higher than are those of Howarth et al. (2011), who estimat ed 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, whic h 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, res earchers — taking both variation in the frequency of liquid unloadings a nd the significant uncertainty st emming 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 w ould 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 firs t approach used EPA emissions for 2005 through 2009 and normalized them according to gross NG pr oduction 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 fede ral onshore activities, and the Bureau of Land Management’s 2008 estimate for federal onsho re production of 3,106 Bcf, from which we derived an emission factor of 303 grams of CH 4 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 emissi ons from well equipment and practices, we

examined CO 2 flaring and venting. According to data in EPA (2011), we estimated that flaring would emit 369 grams of CO 2 per million Btu of NG, while acco rding to data provided in GAO (2010), we estimated that flaring would emit 538 grams of CO 2 per million Btu of NG. As NG

also contains CO 2 , vented emissions were estimated to be roughly 41 grams of CO 2 per million Btu of NG (EPA 2011).

Howarth et al. (2011) developed their meth ane emissions for well equipment leakage and venting from GAO and calculated an emissions l eakage 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 CO 2 emissions for flaring or venting.

15Final ANL/ESD/11-11

December 2011

2.2.6 Recovery Pipeline to Compression Station

Once the shale gas is produce d, it is directed from the we lls 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 gather ing station that collects gas produced within a 4- to 6-mile radius. From the gathering station, th e gas is conveyed into a 12-inch diameter pipe toward local compression stations, where the gas is processed and pressurize d prior to delivery to the main pipeline. The compression station typi cally processes gas produced within a 10- to

20-mile radius. To determine the material and fu el 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 pipelin e. Although the steps can be run in parallel to reduce the total am ount of time spent at a site, diesel-consuming equipment is required for each stage and can in clude hydraulic excavators or pipelayers. As GREET already contains inventory and emissi ons associated with the main trunkline (Wang 1999; He and Wang 2000), this analysis focused on the installa tion of the smaller pipelines that feed into the main line at the co mpression 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 assu med that the equipment would run at 70% capacity duri ng 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 equipmen t 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 prot ective coating, the pipe is lowe red into the trench and then backfilled with soil (Kern River Gas Transmissi on 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 th e compressor station. Table 10 pr esents the material and fuel requirements for installing the pipelines from the wellhead to the compression station.

16Final ANL/ESD/11-11

December 2011

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 em issions estimates was the realization that the methane reductions reported by the Natural Ga s STAR Program were larger than the total unmitigated emissions calculated using its previous methodology. In our analysis, the unmitigated emission factors for each activity associ ated with natural gas recovery were adjusted to represent real-world conditions according to EPA aggr egated emissions reduction data. However, although the aggregated emissions data from EPA (2011) show reductions from both the Natural Gas STAR Program and the Natio nal 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 CH 4 reductions into three categories: (1) unconventional well completions, (2) conventional liquid unloadings, and (3) well e quipment venting and leak age. As the Natural Gas STAR Program only provides partially aggreg ated results to protect confidential business information, the reduction data lack details. Through background information provided by EPA, we separated most of the reduc tions from RECs and technologi es 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 be nefit in reducing methane emissions. In EPA GHG inventory estimates, emissions from flar ing are included under NESHAP reductions, as states such as Wyoming require that vented em issions from well completions and workovers be

flared. EPA assumed that in states without th ese regulations, such as Texas, Oklahoma, and New Mexico, no flaring would occur. EPA esti mated that approximately 51% of the total number of unconventional wells in Texas, Ok lahoma, 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.

17Final ANL/ESD/11-11

December 2011

The EPA conducts quality assurance and control checks of th e Natural Gas STAR reductions prior to incorporating them into its inventory estimates. While the emissions

reductions from Natural Gas STAR and NESHAP ar e considerable at approximately 30% of the unmitigated emissions in 2009, detailed informa tion is limited. To address some of the uncertainty in these estimates, we developed dist ribution functions for thes e reductions. For shale completions, most of the uncertainty was attri butable to flaring assumptions: thus, our lowreduction reduction scenario assumed only reduc tions 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 reduc tions (41%); and fina lly, 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, th ere was significant uncertainty associated with liquid unloadings as the Natu ral 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. Th erefore, we developed a lowreduction reduction scenario for liquid unloa dings based on reported Natural Gas STAR reductions (8%) and a high-reduction reduction scen ario where we adjusted for the sunsetting period (15%), while our Base Case is the av erage 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 sunset ting 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 li quids) 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 tr ansmission pipeline netw ork. At times, NG is delivered directly from the transmission network to industrial customers. Alternatively, the gas may be stored underground or liquefied and stor ed in aboveground tanks. Before residential and commercial customers access the gas, its pre ssure is reduced and it travels through the distribution network of low-pre ssure pipes that are often und erground. 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, tr ansmission and storage, and distribution.

18Final ANL/ESD/11-11

December 2011

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 st orage, and distribution, it is assumed that shale gas would be treated in a manner similar to that of conventional natura l gas. As a result, the existing pathway in GREET, as described in Wa ng 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 appropr iate. To calculate methane leakage emissions from NG processing, T&S, and distribution sectors, we divided the averag e 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 th e calculation of the emission factors is

therefore reasonable.

We also examined vented CO 2 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 CH 4 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 s ectors and that of Howarth et al. (2011). For the pr ocessing sector, Howart h et al. (2011) used the mean emissions facility-level gas-processing emission factor for fugitive CH 4 of 0.19% as provided in the American Petroleum Institute’s (API’s) Compendium to estimate processing sector emissions (Shires et al. 2009). API develope d a range of 0% to 0.19% for th ese emissions, with the lower bound of zero representing wells that produce pipe line-ready gas that needs no processing. API did not explicitly estimate CO 2 emissions from AGR) vents in thei r analysis. Shires et al. (2009) use data from the 1990s, such as the 1993 volume of total gas processed; they state that the

19Final ANL/ESD/11-11

December 2011

uncertainty associated with the reported emissi on 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 fact ors 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 Russi an NG transmission and distribution network (Lelieveld et al. 2005). The estimate of NG leak age in the Russian T&S and distribution sectors is likely an overestimate of emissions for these s ectors in the United States for several reasons. First, an examination of emissions suggests th at the activity and emi ssion 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 outdate d U.S. emissions rates from 2002 and earlier. In the United States, this sector has seen emissi ons decrease significantly by 13% between 1990 and 2009 with the adoption of lower-emitting te chnology, 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 equivalen t 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 fo r 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 deplet ing the amount of gas that ultimately is sold. Howarth et al. (2011) asse rt that these factors (except gas theft) are randomly distributed and therefore will not yield a high or low bias in estimates of NG leak age. However, others assert

20Final ANL/ESD/11-11

December 2011

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 (A rgonne 2011; see also http://gr eet.es.anl.gov/main ). To explore energy and emissions issues associated with sh ale gas and conventional gas, we used the GREET model to develop a shale gas pathway, to estimat e up-to-date life-cycle GHG emissions of shale and conventional gas energy options, and to qua ntify the uncertainties in the estimated GHG emissions of both technologies.

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

functions as described in S ection 2.2, we used GREET’s stocha stic 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 sy stem 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 cap acity would be added to the NG system to

handle the increased demand betw een 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 Emissi ons Factors with Harrison et al. (1996)

CH 4 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

21Final ANL/ESD/11-11

December 2011

As presented in Section 2.2, we updated CH 4 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 bot h 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 calculat ed from EIA Form-906 “Power Plant Report” (EIA undated). For coal power plants, efficien cies were estimated at 34% for conventional pulverized coal boilers and 42% for superc ritical boilers, according to IEA (2006).

For a passenger car, we assumed a fu el economy of 29 miles per gallon gasolineequivalent (mpgge). We assumed that a comp ressed 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% re duction as compared to the gasoline car.

Several studies have examined the fuel c onsumption 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-igniti on diesel engine (Bar nitt 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-We stport (in Adams and Home 2010), the 8.1-liter ISL G NG engine can either match an equivalent di esel 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 fo r our low estimate and a 10% reduction in fuel economy for our high estimate. The mean value wa s assumed to be our Base Case. A summary of our end-use efficiency assumptions is shown in Table 14.

22Final ANL/ESD/11-11

December 2011

TABLE 14 End-Use Efficiency Assumptions for GR EET 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 th e cumulative radiative forcing between the time a unit of gas is emitted and a given time horizon, expressed relative to

that for CO 2 . 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 re latively short perturbation lifetime (12 years),

whereas CO 2 can last in the air for a long time. Howa rth et al. (2011) use results from a recent study by Shindell et al. (2009), wh ereas our analysis relies on the IPCC’s current, published

23Final ANL/ESD/11-11

December 2011

results (IPCC 2007). Table 15 presents the GWPs th at 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

Source CO 2 CH 4 N 2 O CO 2 CH 4 N 2 O

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

24Final ANL/ESD/11-11

December 2011

3 RESULTS AND DISCUSSION

The life-cycle GHG emissions of shale and conventional NG were evaluated according to three functional units —grams of CO 2 equivalent per kilowatt-hour produced (gCO 2 e/kWh), grams of CO 2 equivalent per vehicle mile driven (gCO 2 e/mile), and grams of CO 2 equivalent per megajoule produced (gCO 2 e/MJ) — over two GWP time horizons (i.e., 100-year and 20-year horizons). The results are presented and the impact of parameter uncertain ty 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 th e 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 CoalWTWGHGEmissions(gCO2e/kWh) 1,400

1,200

1,000

800

600

400

200

0

25Final ANL/ESD/11-11

December 2011

Figure 4 illustrates emissions in gCO 2 e per mile for passenger cars. Considering a 100-year GWP horizon, there is no statistically si gnificant difference in well-to-wheels (WTW) life-cycle GHG emissions among fuels on a ve hicle-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 c onsidering 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 conventi onal 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 GasWTWGHGEmissions(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 consider ing a 20-year GWP horizon, CNG buses emit significantly more GHGs than do their petroleum-fu eled 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.

26Final ANL/ESD/11-11

December 2011

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 GasWTWGHGEmissions(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 gCO 2 e/MJ. For both NG pathways, the emissions from direct fuel com bustion are the largest c ontributors to life-cycle GHG emissions. Shale gas shows fewer GHG emi ssions than does conventional NG per MJ. This result is mainly attributable to the large CH 4 emissions associated with liquid unloadings

and the lower EUR for a conventional NG we ll. The further breakdown of upstream and infrastructure emissions for the pathways enables examination of the relative importance of CH 4 leakage and CO 2 venting and flaring. For NG pathways, CH 4 venting and leakage during NG recovery operations are the largest upstream GH G emissions source. Liquid unloadings are a key factor for conventional NG, whereas completi on and workover emissions are significant for shale gas. GHG emissions associated with mate rials and fuels for infrastructure are almost negligible in terms of the life-cycle emissions. Th e chart also shows the relative uncertainties for each pathway based on our stochastic simulations.

27Final ANL/ESD/11-11

December 2011

0 20 40 60 80 100 120

100 20 100 20GHGEmissions(gCO2e/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 CH 4 venting and leakage during NG recovery operations serving as the largest upstream GHG emissions sources and with liqui d unloadings and EUR si gnificantly 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 CH 4 venting during liquid unloadings contributes the most uncertainty to our GHG emissions estimates under both

time horizons. The next most significant parameter is CH 4 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

CH 4 is much larger under the 20-year time horizon th an it is under the 100-year time horizon, the impact of the CH 4 venting during liquid unloading is greater under the former.

The shale gas tornado charts show trends si milar to those of the conventional NG tornado charts outside of liquid unloadings as it is assume d the unloadings are not to be required for shale

28Final ANL/ESD/11-11

December 2011

gas wells (EPA 2010). The other major differenc e between the two pathways (as previously noted) is that the completion and workover emissi ons associated with shale gas wells are much more significant than are similar emi ssions associated with conventional NG. However, completion and workover emissions have only mode rate impacts on the uncertainty of life-cycle emissions, although the impacts are more pronoun ced under the 20-year time horizon. Under both time horizons, uncertainties in CH 4 venting from well equipment shows the largest impact on life-cycle GHG emissions for the shale NG path way 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 Resu lts for Shale and NG Pathways (100-Year Time Horizon)

29Final ANL/ESD/11-11

December 2011

‐ 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 Resu lts for Shale and NG Pathways (20-Year Time Horizon)

30Final ANL/ESD/11-11

December 2011

4 SUMMARY AND IMPLICATIONS

The analysis demonstrates that upstream CH 4 leakage and venting are key contributors to the upstream emissions of the NG pathway. These em issions can significantly reduce the benefits of producing NG as compared to coal or petroleu m. The fact that only li mited 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 natura l gas in the U.S. energy supply.

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

needs to be calculated for the va rious technologies that are empl oyed 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 unlo adings, as not all well s 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 practi ces in different plays or geol ogic 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 invent ory of these emissions. Flaring pr actices should also be examined for liquid unloading operations by both st ate 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 na tural gas that are produced duri ng 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 shal e gas well needs further examination. The decision to rework a

well will be based on a number of factors that affect the economi cs 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 th e percentage of wells that are employing emissions-reduction practices. This identification includes completions and workovers implementing REC technol ogies and flaring practices fo r wells both with and without RECs. Such information could be gathered by ex amining state regulations and industry practices and could provide greater certain ty regarding the emissions from shale gas. Finally, as the NG industry gains more experience with SG producti on through the lifetime of the well, the accuracy of EUR projections will hopefully improve.

Environmental management and GHG emissi ons reduction strategies need to be exercised in large-scale operation for shale and conventional NG to re duce the environmental and energy burdens associated with producing th ese fuels. The voluntary partnership of the natural gas industry and EPA under the Natura l Gas STAR Program has helped reduce CH 4 emissions; however, further efforts could be und ertaken to extend the ap plication of emissionsreduction projects across the industry, devel op new mitigation measures, and address the remaining environmental issues associated with natural gas production and transmission.

31Final ANL/ESD/11-11

December 2011

This page intentionally left blank.

32Final ANL/ESD/11-11

December 2011

5 REFERENCES

Adams, R., and D.B. Home, 2010, Compressed Natural Gas (CNG) Transit Bus Experience Survey — April 2009–April 2010 , NREL/SR-7A2-48814, National Renewable Energy Laboratory: Golden, Colo.

Argonne (Argonne National Laboratory), 2011, Gr eenhouse Gases, Regulated Emissions, and Energy Use in Transportation Model. Availa ble at: http://greet .es.anl.gov/ (accessed June 1, 2011).

Barnitt, R., and K. Chandler, 2006, New York City Transit (NYCT) Hybrid (125 Order) and CNG

Transit Buses , NREL/TP-540-40125, National Renewable Energy Laboratory: Golden, Colo.

BLM (U.S. Bureau of Land Management), 2010, MCF of Natural Gas Produced Yearly.

Available at: http://www.blm.gov/pgdata/e tc/medialib/blm/wo/MINERALS__REALTY

__ AND_RESOURCE_PROTECTION_/energy/oil___ga s_statistics.Par.92178.File.dat/chart_2009
_12.pdf. (accessed May 25, 2011).

Bourgoyne, A.T., K.K. Millheim, M.E. Chenevert, and F.S. Young, 1991, Applied Drilling Engineering , Society of Petroleum Engin eers: Richardson, Texas, p. 301.

Bracken, K., 2008, Reduced Emission Completions in DJ Basin and Natural Buttes , Natural Gas STAR Producer’s Technology Transfer Workshop, Rock Springs, Wyo., May 1.

Brinkman, N., M. Wang, T. Weber, and T. Darlington, 2005, Well-To-Wheels Analysis of Advanced Fuel/Vehicle Systems — a North Am erican Study of Energy Use, Greenhouse Gas
Emissions, and Criteria Pollutant Emissions ; Argonne, IL.

Caterpillar, 2010, 315DL Hydraulic Excavator . Available at: http://xml.catmms.com/servlet / ImageServlet?imageId=C414764 (accessed August 2, 2011).

Chandler, K., E. Eberts, and M. Melendez, 2006, Washington Metropolitan Area Transit Authority: Compressed Natural Gas Transit Bus Evaluation , NREL/TP-540-37626, National Renewable Energy Laboratory: Golden, Colo.

Chesapeake Energy, 2010, Investor Presentation , 2010 Institutional Investor and Analyst Meeting, Oklahoma City, Okla., Oct. 13.

Davis, S.C., S.W. Diegel, and R.G. Boundy, 2010, Transportation Energy Data Book:

Edition 29 , Oak Ridge National Laboratory, ORNL-6986.

Dedikov, J.V., G.S. Akopova, N.G. Gladkaja, A.S. Piotrovskij, V.A. Markellov, S.S. Salichov,

H. Kaesler, A. Ramm, A. Müller von Blumencr on, and J. Lelieveld, 1999, “Estimating Methane Releases from Natural Gas Production and Transmission in Russia,” Atmospheric

Environment 33, 3291–3299.

33Final ANL/ESD/11-11

December 2011

Delorme, A., D. Karbowski, R. Vijayagopal, and P. Sharer, 2009, Evaluation of Fuel Consumption Potential of Medium and Heavy Duty Vehicles through Modeling and Simulation

, Report to the National Academy of Sciences. Available at: http://www.autonomie.net/docs/ 6%20-%20Papers/nas_mediumheavyduty_2009.pdf (accessed August 1, 2011).

DOE (U.S. Department of Energy), 2011, Fuel Economy, Office of Energy Efficiency and Renewable Energy. Available at: http:// www.fueleconomy.gov / (accessed May 25, 2011).

Eckhardt, M., B. Knowles, E. Maker, and P. Stork, 2009, IHS U.S. Industry Highlights , Houston, Tex., Feb–Mar.

EIA (U.S. Energy Informa tion Administration), 2011a, Annual Energy Outlook 2011, DOE/EIA0383(2011). Available at: http://www.eia.gov/ forecasts/aeo/pdf/0383(2011).pdf (accessed November 21, 2011).

EIA, 2011b, U.S. Natural Gas Summary: Production . Available at: http://www.eia.gov / dnav/ng/ng_sum_lsum_dcu_nus_a.htm (accessed June 1, 2011).

EIA, 2009, Shale Gas Plays, Lower 48 States . Available at: http://www.eia.doe.gov / oil_gas/rpd/shaleusa2.pdf (accessed December 15, 2010).

EIA, undated, Form EIA-906: Power Plant Report, 2007–2008. Available at: http://www.eia.gov/cneaf/el ectricity/page/eia906_920.ht ml (accessed May 12, 2011).

EPA (U.S. Environmental Protection Agency), 2011, Inventory of U.S. Greenhouse Gas
Emissions and Sinks: 1990–2009, EPA 430-R-11-005, U.S. Environmental Protection Agency: Washington, D.C.

EPA, 2010a, 2009 Natural Gas STAR Program Accomplishments . Available at: http://www.epa.gov/gasstar/documents/ngs tar_accomplishments_2009.pdf (accessed May 25, 2011).

EPA, 2010b, Greenhouse Gas Emissions Reporting from the Petroleum and Natural Gas Industry, Background Technical Support Document , U.S. Environmental Protection Agency: Washington, D.C.

EPA, 2007, Reducing Methane Emissions during Completion Operations , Natural Gas STAR Producer’s Technology Transfer Works hop, Glenwood Springs, Colo., Sept. 11.

EPA, 2006, Installing Plunger Lift Systems in Gas Wells: Lessons Learned from Natural Gas
STAR Partners, U.S. Environmental Protection Agen cy: Washington, D.C. Available at: http://epa.gov/gasstar/documents/ll_pl ungerlift.pdf . (accessed May 25, 2011).

34Final ANL/ESD/11-11

December 2011

EPA, 2004a, Exhaust and Crankcase Emission Factors for Nonroad Engine Modeling — Compression-Ignition, NR-009c, EPA420-P-04-009, revised April. Available at: http://www.epa.gov/OMS/models/nonr dmdl/nonrdmdl2004/420p04009.pdf (accessed April 16, 2010)

.

EPA, 2004b, Green Completions, Natural Gas STAR Producer’s Technology Transfer Workshop, Houston, Tex., Sept. 21.

EPA, 1993, Development Document for Effluent Limitations Guidelines and New Source Performance Standards for the Offshore Subcate gory of the Oil and Gas Extraction Point Source Category , EPA 821-R/93-003.

Gaudlip, A.W., L.O. Paugh, and T.D. Hayes, 2008, “Marcellus Shale Water Management Challenges in Pennsylvania,” presented at the 2008 SPE Shale Gas Production Conference, Fort Worth, Tex., November 16–18.

Geankoplis, C.J., 1993, Transport Processes and Unit Operations, 3 rd Edition , Prentice-Hall, Inc.: Englewood Cliffs, New Jersey, p 133–134.

GAO (U.S. Government Accountability Office), 2010, Federal Oil and Gas Leases: Opportunities Exist to Capture Vented and Flared Natural Gas, Which Would Increase Royalty Payments and Reduce Greenhouse Gases , GAO-11-34, U.S. Government Accountability Office: Washington, D.C.

GWPC and ALL (Ground Water Protecti on Council and ALL Consulting), 2009, Modern Shale Gas Development in the United States: A Primer , prepared for U.S. Department of Energy Office of Fossil Energy and National Energy Technology Laboratory. Available at: http://fossil.energy.gov/programs/ oilgas/publications/naturalga s_general/Shale_Gas_Primer _2009.pdf (accessed December 15, 2010).

GTI (Gas Technology Institute), 2001, Gas Resource Database: Unconventional Natural Gas and Gas Composition Databases , Second Edition, GRI-01/0136.

Hanle, L., 2011, personal communication among L. Hanle, U.S. Environmental Protection Agency, D. Sechler, ICF International, and A. Burnham, C. Clark, J. Dunn, and J. Han, Argonne National Laboratory, May 9.

Harrison, M.R., L.M. Campbell, T.M. Shires, and R.M. Cowgill, 1996, Methane Emissions from the Natural Gas Industry, Volume 2 , EPA/600/R-96/080B, U.S. Environmental Protection Agency: Washington, D.C.

He, D., and M. Wang, 2000, “Contribution of Feedst ock and Fuel Transportation to Total FuelCycle Energy Use and Emissions,” SAE paper 2000-01-2976.

Howarth, R.W., R. Santoro, and A. Ingraffea, 2011, “Methane and the Greenhouse-Gas Footprint of Natural Gas from Shale Formations,” Climatic Change 106, 679–690.

35Final ANL/ESD/11-11

December 2011

IEA (International Energy Agency), 2006, Focus on Clean Coal, International Energy Agency: Paris, France.

INTEK (INTEK, Inc.), 2011, Review of Emerging Resources: U.S. Shale Gas and Shale Oil Plays , prepared for the Energy Informati on Administration: Washington, D.C.

IPCC (Intergovernmental Panel on Climate Change), 2007, Climate Change 2007: The Physical Science Basis: Contribution of Working Group I to the Fourth Asse ssment Report of the Intergovernmental Panel on Climate Change , Cambridge University Press.

Kern River Gas Transmission Company, 2010, Construction Fact Sheet . Available at: http://www.kernrivergas.com/InternetPorta l/DesktopModules/ViewDocu ment.aspx?DocumentI D=734 (accessed December 15, 2010).

Kirchgessner, D.A., R.A. Lott, R.M. Cowgill, M. R. Harrison, and T.M. Shires, 1997, “Estimate

of Methane Emissions from th e U.S. Natural Gas Industry,” Chemosphere 35, 1365–1390.

Lelieveld, J., S. Lechtenbohmer, S.S. A ssonov, C.A.M. Brenninkmeijer, C. Dienst,

M. Fischedick, and T. Hanke, 2005, “Greenhous e Gases: Low Methane Leakage from Gas Pipelines,” Nature 434, 841–842.

Mansure, A.J., 2010, “Review of Past Geotherm al Energy Return on Investment Analyses,”

GRC Transactions , Geothermal Resources Council, Davis, CA.

Mantell, M.E., 2010a, personal communication between M.E. Ma ntell, Chesapeake Energy, and

C.B. Harto, Argonne National Laborat ory, Washington, D.C., December 20.

Mantell, M.E., 2010b, “Deep Shale Natural Ga s and Water Use, Part Two: Abundant, Affordable, and Still Water Efficient,” Water/Energy Sustainability Symposium at the 2010

GWPC Annual Forum , Pittsburgh, Penn.

Nakles, D.V., I. Ortiz, and J.R. Frank, 1992, “A n Analysis of Management Strategies for Produced Waters from Natural Gas Production,” Produced Water Technological/Environmental

Issues and Solutions , Environmental Science Research 46, 73–88.

Overbey, W.K., R.S. Carden, C.D. Locke, S.P. Salamy, T.K. Reeves, and H.R. Johnson, 1992, Site Selection, Drilling, and Completion of Two Horizontal Wells in the Devonian Shales of West Virginia, prepared for U.S. Department of Energy, DOE/MC/25115--3116.

Percival, P., 2010, “Update on ‘Lost and Un accounted for’ Natural Gas in Texas,” Basin Oil &

Gas , July/August. Available at: http://fwbog.com /index.php?page=article&ar ticle=248 (accessed June 1, 2011).

36Final ANL/ESD/11-11

December 2011

Radback Energy, 2009, “Appendix 5.1E Construction Data,” Contra Costa Generating Station

— Application for Certification , prepared for the Californi a Energy Commission, Docket 09­

AFC-4. Available at: http://www.energy.ca.gov/s itingcases/oakley/docu ments/applicant/afc / Volume%202/CCGS_ Appendix%205.1E_C onstruction%20Data.pdf (accessed December 21, 2011).

Range Resources, 2010a, Well Record and Comple tion Report: Baker Carol 5H. Available at: http://www.rangeresources.com/getdoc /0651ae63-6b22-49f6-91b0-ba8931870094/Baker-Unit

5H.aspx (accessed May 25, 2011).

Range Resources, 2010b, Well Record and Comple tion Report: Baker Carol 4H. Available at: http://www.rangeresources.com/getdoc/ 87529e5c-c15f-4846-b450-b44a e68b378f/Baker-Unit

4H.aspx (accessed May 25, 2011).

Range Resources, 2010c, Well Record and Comple tion Report: Baker Carol 6H. Available at: http://www.rangeresources.com/getdoc/ d8bdbf42-0028-45aa-bd4c-324a3a1b78f5/Baker-Unit

6H.aspx (accessed May 25, 2011).

Samuels, J., 2010, Emission Reduction Strategies in the Greater Natural Buttes , Natural Gas STAR Producer’s Technology Transfer Workshop, Vernal, Utah, March 23.

Shindell, D.T., G. Faluvegi, D.M. Koch, G.A. Schmidt, N. Unger, and S.E. Bauer, 2009, “Improved Attribution of Clim ate Forcing to Emissions,” Science 326, 716–718.

Shires, T.M., C.J. Loughran, S. Jones, and E. Hopkins, 2009, Compendium of Greenhouse Gas Emission Methodologies for the Oil and Natural Gas Industry , American Petroleum Institute: Washington, D.C.

Stinson, K., 2008, “Water Resource Management in the Barnett Shale,” Meeting of the Texas Association of Clean Water Agencies, Fort Worth, Tex., Nov. 21. Available at: http://tacwa.org/images/Water_Resource_Mana gement_in_the_Barnett_Shale.pdf (accessed August 4, 2011).

Swindell, G., 2001, “Changes in the Performance of Texas Gas Wells,” SPE Permian Basin Oil and Gas Recovery Conference, May 15–17, Midland, Tex.

Tester, J., et al., 2006, The Future of Geothermal Energy : Impact of Enhanced Geothermal Systems (EGS) on the United States in the 21 st Century , Massachusetts Institute of Technology.

Available at: http://geothermal.inel.gov/publicat ions/future_of_geotherm al_energy.pdf (accessed August 2010).

Veil, J.A., 2010, Water Management Technologies Used by Marcellus Shale Gas Producers

, ANL/EVS/R-10/3, Argonne National Laboratory; Argonne, Ill.; July.

Wang, M., Y. Wu, and A. Elgowainy, 2007, Operation Manual: GREET 1.7 , ANL/ESD-05-3, Center for Transportation Research, Argonne National Laboratory, Argonne, Ill.

37Final ANL/ESD/11-11

December 2011

Wang, M.Q., 1999, GREET 1.5 — Transportation Fuel-Cycle Model: Volume 1, Methodology, Use, and Results, ANL/ESD-39, Vol. 1, Center for Transportation Research, Argonne National Laboratory, Argonne, Ill.

Wang, M., and H. Huang, 1999, A Full Fuel-Cycle Analysis of En ergy and Emissions Impacts of Transportation Fuels Produced from Natural Gas , ANL/ESD-40, Center for Transportation Research, Argonne National Laboratory, Argonne, Ill., Dec.

38Final ANL/ESD/11-11

December 2011

40