Shale Gas Production: 

Potential versus Actual GHG Emissions 

Francis O’Sullivan and Sergey Paltsev

Report No. 234

November 2012
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1

Shale Gas Production: Potential versus Actual GHG Emissions

Francis O’Sullivan*† and Sergey Paltsev*‡

Abstract

Estimates of greenhouse gas (GHG) emissions from shale gas production and use are controversial. 

Here we assess the level of GHG emissions from shale gas well hydraulic fracturing operations in the 

United States during 2010. Data from each of the approximately 4,000 horizontal shale gas wells 

brought online that year is used to show that about 900 Gg CH4 of potential fugitive emissions were 

generated by these operations, or 228 Mg CH4 per well—a figure inappropriately used in analyses of 

the GHG impact of shale gas. In fact, along with simply venting gas produced during the completion 

of shale gas wells, two additional techniques are widely used to handle these potential emissions, gas 

flaring, and reduced emissions “green” completions. The use of flaring and reduced emission 

completions reduce the levels of actual fugitive emissions from shale well completion operations to 

about 216 GgCH4, or 50 Mg CH4 per well, a release substantially lower than several widely quoted 

estimates. Although fugitive emissions from the overall natural gas sector are a proper concern, it is 

incorrect to suggest that shale gas-related hydraulic fracturing has substantially altered the overall 

GHG intensity of natural gas production.

Contents

1. INTRODUCTION...................................................................................................................1

2. HYDRAULIC FRACTURING AND GHG EMISSIONS......................................................2

3. ANALYSIS .............................................................................................................................3

4. CONCLUSIONS.....................................................................................................................7

5. REFERENCES........................................................................................................................8

APPENDIX

1. INTRODUCTION

Over the past decade, economically recoverable shale gas has transformed the U.S. natural 

gas industry, with some analysts characterizing it as a “revolution” (Deutch, 2011; Jacoby et al., 

2012). With shale driven growth, the U.S. has become the world’s largest gas producer (IEA, 

2011). The low gas prices that have accompanied this production boom have led to a renewed 

growth in gas demand by industrial users, a recovery viewed as extremely unlikely just a decade 

ago. The rise of shale gas has not been without controversy, however, with important concerns 

raised regarding water pollution (Osborn et al., 2011), greenhouse gas (GHG) emissions, 

particularly those related to hydraulic fracturing (Howarth et al., 2011a; Howarth et al., 2011b; 

Howarth et al., 2012), and uncertainty in estimates of the resource scale (Jacoby et al., 2012; 

Urbina, 2011; MIT, 2011; Lee et al., 2010). In this analysis we focus on the issue of fugitive 

GHG emissions associated with shale gas fracturing and provide estimates of potential and actual 

emissions.

 

* MIT Energy Initiative, Massachusetts Institute of Technology, 77 Massachusetts Avenue, Cambridge, MA 02139, 

USA.

† Corresponding author. Email: frankie@mit.edu, Tel: 617-715-5433.

‡ MIT Joint Program on the Science and Policy of Global Change, Massachusetts Institute of Technology, 77 

Massachusetts Avenue, Cambridge MA 02139, USA.
2

2. HYDRAULIC FRACTURING AND GHG EMISSIONS

The economic production of shale gas is only possible through the use of hydraulic fracturing 

to increase production rates from the extremely low-permeability shale formations. The 

hydraulic fracturing process has two main stages: injection and flowback. During injection, a 

slurry made up of a carrier fluid, typically water, and a proppant agent, typically sand, is forced 

into the well at pressures significant enough to induce fractures in the reservoir rock. These 

propped fractures allow gas in the formation to flow from the well at economically acceptable 

rates. After the injection phase is completed, flowback takes place. Here some of the initially 

injected fluid returns to the surface over the course of a week or more. During flowback, the well 

also begins to produce gas. It is the amount of this gas, and how it is handled, that has been 

central to the debate about the GHG intensity of shale development. In 2011, the EPA revised 

upwards its GHG inventories for the natural gas system (EPA, 2011), and some have attributed 

this increase to the expanded production of shale gas and the associated increase in hydraulic 

fracturing. It has been argued that large amounts of gas are directly vented to the atmosphere 

during flowback, and that this means shale gas has a significantly higher GHG intensity than 

conventional gas production (Howarth et al., 2011a, 2011b). In fact, with some specific 

assumptions about the global warming potential of gas it has been suggested that the GHG 

impact of shale gas might be greater than that of coal on a lifetime basis (Howarth et al., 2011a, 

2011b). This perspective has been widely articulated via popular media (e.g., Soraghan, 2011; 

McDonald, 2011). 

Debate regarding this issue has been added to by research published by NOAA scientists 

(Petron et al., 2012) that studied methane and other fugitive GHG levels in air samples taken in 

Colorado’s Denver-Julesburg oil and gas basin. Their results suggest that fugitive emissions in 

Colorado’s Weld County during 2008 amounted to 3.8% of the county’s total gas production that 

year. The study area, the Denver-Julesburg Basin is a tight sandstone formation that produces 

appreciable amounts of both gas and oil. In 2008, the year of the study, there were 850 tight gas 

wells and 1583 oil/condensate wells drilled in the Denver-Julesburg area (HPDI, 2012). An 

important point regarding the study is that it assessed fugitive emissions levels from the entire 

gas and oil production system in the basin, which includes many complex upstream and 

midstream systems widely known as fugitive emissions sources including gathering pipelines, 

compressor station and condensate tanks (EPA, 2012a; EPA, 2011). Nevertheless, some have 

interpreted the NOAA analysis as a quantification of fugitive emissions resulting from hydraulic 

fracturing alone (Tollefson, 2012).

The conclusions of Howarth et al. (2011b), have been questioned by some analysts (DOE, 

2011; Cathles et al., 2012), and several groups working on the topic have come to different 

conclusions regarding the relative GHG impact of shale gas. Burnham et al. (2011) concludes 

that the life-cycle GHG emissions from shale gas are slightly less than that of conventional gas, 

Weber et al., (2012) suggest they are approximately equal, while Jiang et al. (2011), Stephenson 

et al. (2011) both conclude that shale gas has a life-time GHG impact that is slightly higher than 

that of conventional gas. All of these groups do however conclude that the GHG impact of 
3

electricity generated using shale gas is significantly less than that of generated with coal. 

Howarth et al., stand by their conclusions (Howarth et al., 2012), pointing out the significant 

upward revision in EPA estimates of fugitive emissions from unconventional wells in the EPA’s 

2011 inventory (EPA, 2011). Their conclusions are also supported, at least in the case of Barnett 

shale wells, by the analysis in Hultman et al. (2011).

3. ANALYSIS

Analysis of this controversy begins with quantification of potential emissions produced during 

well flowback. This requires knowledge of the duration of the flowback stage, and the rate of gas 

production during that period. The EPA assumes that the flowback period lasts from 3 to 10 days 

(EPA, 2011). A recent industry-sponsored survey suggests 3 to 8 days (ANGA, 2012). The 

analysis of Howarth et al., (2011a) assumes 9-days for the wells in the Barnett shale and 10 days 

in the Haynesville shale. Here we use a 9-dayflowback period for wells in each of the major 

shale plays. Although it is certain that flowback durations vary from well to well, our 9-day 

assumption is at the conservative end of the reported range. Measured data on the rate of 

flowback from Haynesville shale wells reported by Fan et al. (2010) shows that within 9-10 

days, the level of fluid production falls by ~75%, and this confirms that 9 days is a reasonable 

estimate. We assume that gas production during flowback from a given well can be modeled as 

ramping linearly from zero at flowback initiation to the peak recorded production rate for that 

well at flowback completion. This assumption is supported by data presented during a recent 

EPA workshop (EPA, 2012b), and by both simulation results and recorded gas production rates 

during the flowback of shale wells reported by Fan et al. (2010). Integrating this production 

profile over the 9-day flowback period yields the potential fugitive emissions estimate for each 

well. 

In this report we assess the level of fugitive GHG emissions resulting from the hydraulic 

fracturing of 3,948 horizontally drilled shale gas wells brought online in the U.S. during 2010 

(HPDI, 2012), assuming a number of gas handling scenarios, which involve different levels of 

venting, flaring and gas capture. Table 1 shows the potential emissions estimates assuming the 

mean well peak production rates in each shale play for 2010. 

Table 1. Per-well hydraulic fracturing-related potential fugitive emissions from 2010 vintage 

U.S. horizontal shale gas wells (Source: Authors’ calculations based on HPDI 2012).

Per-well potential emissions:

(1x103m3 natural gas)

Barnett Fayetteville Haynesville Marcellus Woodford

Mean: 273 296 1,177 405 487

P80: 385 409 1,538 573 685

P50: 234 285 1,108 342 413

P20: 138 167 754 195 230
4

The table also illustrates the substantial well-to-well variability in potential emission levels by 

showing the estimates for the 20th, 50th and 80th percentile peak production rates. The peak 

production rate data underlying the values reported in Table 1 can be seen in Table A1 of the 

Appendix. The variation in initial well productivity within and between the shale plays is driven 

in large part by underlying geological, geo-mechanical, geo-chemical and petrophysical 

characteristics of the shale formations. Reservoir pressure, total organic content, thermal 

maturity, porosity and other factors can all differ within and between plays, and this in turn 

results in well-to-well variation in productivity (Jarvine et al., 2007; Curtis et al., 2012; Hammes 

et al., 2011, Baihly, et al., 2010). Aggregating the data in Table 1 for the total number of wells 

brought online in 2010 yields an overall estimate of hydraulic fracturing-related potential 

fugitive emissions from the five plays of 902 Gg CH4. The details of this aggregation are shown 

in Table 2. For comparison, the EPA GHG inventory for the upstream gas sector estimates total 

2010 fugitive emissions of 6,002 Gg CH4.

Table 2. Total hydraulic fracturing-related potential fugitive emissions from U.S. shale gas 

wells brought online in 2010 (Source: Authors’ calculations based on HPDI 2012).

Barnett Fayetteville Haynesville Marcellus Woodford All Plays

Mean per-well potential 

fugitive emissions:

(1x103 m3 of natural gas)

273 296 1,177 405 487 —

# of horizontal wells 1,785 870 509 576 208 3,948

Total potential fugitive 

emissions:

(1x106 m3 of natural gas)

487 257 599 234 101 1,678

Total potential 

fugitive methane 

emissions: (Gg CH4)

262 138 322 125 54 902

It is useful to compare the per-well potential emissions from Table 1 to the estimated ultimate 

production from wells in each play. There is appreciable uncertainty regarding the level of 

ultimate recovery that can be expected from shale wells. Much of this is due to the limited 

production history of the shale resource and, as yet, not well understood mechanisms of 

production in ultra-low permeability reservoirs (Anderson et al., 2010, Lee et al., 2010). To 

account for this uncertainty we assume two well production lifetimes in this analysis; the 

commonly assumed 30-year lifetime, and a more conservative 15-year lifetime. It is important to 

acknowledge though that there is legitimate debate ongoing regarding whether the productive 

lifetimes of these wells may in fact be appreciably shorter than even our 15-year case (Berman, 

2012; Hughes, 2011). The results of the comparison between potential emissions produced 

during flowback and estimates of ultimate recovery based on 30- and 15-year producing 

lifetimes are shown in Table 3. The results indicate that in most shale plays, hydraulic 

fracturing-related potential fugitive emissions represent 0.4-0.6% of a well’s estimated ultimate 
5

recovery. In the Haynesville, the ratio is higher at 0.8–1%, owing to the high initial production 

and production decline rates in that play, which are due to that particular shale’s highly overpressured reservoir (Baihly, 2010). Should it become clear that shorter lifetimes are more 

representative, then the ratio of potential emissions to ultimate recovery will increase, though not 

proportionally as shale wells tend to be most productive during their early lives. Details of actual 

production dynamics from the ensemble of shale wells drilled since 2005 can be found in section

A2 of the Appendix.

Table 3. Shale gas hydraulic fracturing-related potential fugitive emissions as a percentage 

of estimated ultimate recovery assuming mean well production performance rates and 30-

year and 15-year producing lifetimes (Source: Authors’ calculations based on HPDI, 2012).

Barnett Fayetteville Haynesville Marcellus Woodford

30-year lifetime 0.39% 0.39% 0.78% 0.39% 0.39%

15-year lifetime 0.54% 0.52% 0.99% 0.53% 0.52%

The proportions of the potential fugitive emissions that are vented, flared, or captured and 

sold via a reduced emission “green” completion determine the actual GHG intensity of shale gasrelated hydraulic fracturing. In this analysis we use specific GHG intensities for venting, flaring 

and reduced emission completions of 13.438 kg CO2e, 1.714 kg CO2e and 1.344 kg CO2e 

respectively, based upon a 100-year Global Warming Potential (GWP) for CH4. Schindell et al, 

(2009) argue that the use of a 100-year integration period underestimates the actual warming 

impact of CH4 and suggests that a higher GWP factor, based on a 20-year integration period be 

used instead. Because the various GHGs have different lives in the atmosphere (e.g., on the scale 

of decade for CH4 but centuries for CO2 and thousands of years for some other GHG gases), the 

Intergovernmental Panel on Climate Change (IPCC, 2007) provides this factor for 20-, 100-, and 

500-year integration periods and uses 100-year GWPs. MIT (2011) argues that 20-year GWP 

would emphasize the near-term impact of methane but ignore serious longer-term risks of 

climate change from GHGs that will remain in the atmosphere for hundreds to thousands years. 

For a comparison, the specific GHG intensities of venting, flaring and reduced emissions 

completions assuming a 20-year GWP for CH4 are detailed in section A3 of the Appendix. 

Significant opaqueness surrounds real world gas handling practices in the field, and what 

proportion of gas produced during well completions is subject to which handling techniques. 

Diverse opinions on this question exist even within the gas industry. Some analysts state that gas 

companies have had a policy of not investing in gas conservation measures due to the low rate of 

return. By contrast, an industry survey of unconventional gas producers has suggested that 

reduced emission completions are being used on more than 90% of shale wells completions, and 

that in the case of those wells not subject to a reduced emissions completion, the duration of 

flowback is rarely more than 3 days (ANGA 2012). Some of the contemporary analysis on shale 

gas-related fugitive emissions has not attempted to account for the impact of real world gas 

handling field practice. For example, in Howarth et al. (2011b) it is assumed that all potential 

fugitive emissions are vented. This is an unreasonable assumption, not least because some 
6

producing states have regulation requiring flaring as a minimum gas handling measure. The EPA 

in its quantification of fugitive emissions does assume a certain proportion of gas is flared (EPA, 

2011; EPA, 2012a); however, it does not separate fugitive emission from shale wells with those 

from tight and other unconventional gas sources. Furthermore, the EPA analysis does not 

adequately assess gas capture levels, particularly in regions where flaring is required.

We assess several gas handling scenarios, ranging from the assumption that all potential 

emissions are vented (Howarth et al., 2011b), to that suggested by a gas industry group in which 

93% of potential fugitive emissions are captured (ANGA, 2012). However, our main estimate of 

actual fugitive emissions is based on a “current field practice” gas-handling scenario, where 70% 

of potential fugitives are captured, 15% vented, and 15% flared. This we believe is a reasonable 

representation of current gas handling practices in the major shale plays (EPA, 2012b) (Further 

discussions of gas handling scenarios are presented in section A3 of the Appendix). Table 4

contrasts the level of per-well actual fugitive emissions based upon the assumption of the 

“current field practice” scenario and the “all vented” scenario. Compared to the all-vented 

analysis (Howarth et al., 2011b), which reports emissions from Barnett as 252 Mg CH4/well (or 

370,000 m3 CH4) and 4,638 Mg CH4/well (6,800,000 m3 CH4) for Haynesville, our mean 

estimates are 35.1 Mg CH4/well and 151.3 Mg CH4/well, respectively.

Table 4. Per-well actual fugitive GHG emissions from shale gas-related hydraulic fracturing 

in 2010 (Source: Authors’ calculations based on HPDI 2012).

Barnett Fayetteville Haynesville Marcellus Woodford

Per-well GHG emissions: Mg CH4/well (related CO2 emissions are added based on 100-yr CH4 GWP)

All Vented 146.7 159.1 632.7 217.7 261.8

Current Field Practice 35.1 38.0 151.3 52.1 62.6

Beyond regulation, the methods selected to handle gas during well completions in the field are 

driven by economics. In the case of conventional gas wells, the volumes of potential emissions 

produced during completion are very low. According to the EPA, on average, 1,040 m

3 CH4

(36.36 Mcf) are produced by a conventional well completion (EPA, 2010). The economic value 

of this gas would certainly not justify the use of a reduced emission “green” completion. By 

contrast, the level of potential emissions from shale wells is very large. In Howarth et al. (2011b) 

it is stated that 3.2% of the estimated ultimate recovery from a Haynesville shale well is 

produced during flowback. In that case, 3.2% of estimated ultimate recovery amounts to 

6,800,000 m

3 CH4. This is a very considerable amount of gas and assuming a conservative longrun wellhead gas price of $4.00/MMBtu (MIT, 2011; NYMEX, 2012; EIA, 2012), simply 

venting, or indeed flaring this gas would amount to a revenue loss of $1.2 million for the 

operators. Admittedly, this is an extreme example since the performance of the particular 

Haynesville well in question is not representative of a typical Haynesville well; however, even 

when considering mean shale well performance data, the value of gas produced during flowback 

is substantial, and likely to warrant the cost of capture. Based on our mean estimates of potential 

emissions shown in Table 1, the gross values of capturing this gas using a reduced emission 
7

completion ranges from $39,000 for a Barnett well to $166,000 for a Haynesville well. The 

aggregate gross value of the gas produced during flowback from the 3,948 shale wells 

considered in this study amounts to $320 million. Capturing potential emissions is not without 

cost, of course, but these costs appear to be relatively modest (A detailed discussion of the 

variability in the gross value of gas produced during flowback, and the costs associated with 

reduced emission completions can be found in section A4 of the Appendix.). If the cost of 

reduced emission completion is $1,000 per day as stated by Devon (2008), 95% of the 2010 

Barnett wells yielded positive net revenues, i.e. operators added to the value of their wells by 

capturing the potential fugitive emissions. Even at twice this reported capture cost, $2,000 per 

day, 83% of the 2010 Barnett wells would still positive net revenues, and this trend is repeated in 

the all the other shale plays. The results of a sensitivity analysis exploring the impact of reduced 

emissions completion costs and gas price variation on the 2010 Barnett shale well ensemble are 

shown in Figures A5 and A6 of the Appendix. 

4. CONCLUSIONS

Taking actual field practice into account, we estimate that in 2010 the total fugitive GHG 

emissions from U.S. shale gas-related hydraulic fracturing amounted to 216 Gg CH4. This 

represents, 3.6%, of the estimated 6,002 Gg CH4 of fugitive emissions from all natural gas 

production-related sources in that year (EPA, 2012a; EPA, 2012b). The entire natural gas value 

chain is estimated to have produced 10,259 Gg CH4 of fugitive emissions in 2010, or about 3.1% 

of the Nation’s total GHG inventory (EPA, 2012a; EPA, 2012b). Thus under a goal of GHG 

reduction it is clear that increased efforts must be made to reduce fugitive losses from this 

system. However, it is also clear is that the production of shale gas and specifically, the 

associated hydraulic fracturing operations have not materially altered the total GHG emissions 

from the natural gas sector. Furthermore, for the vast majority of contemporary shale gas wells, 

the revenues gained from using reduced emissions completions to capture the gas produced 

during a typical flowback cover the cost of executing such completions. 

Acknowledgements

The Authors wish to thank Henry Jacoby for his guidance and input in the development of this 

analysis and Audrey Resutek for her help with the manuscript. We are also thankful to three 

anonymous referees of the paper for their useful comments and suggestions. This work was not 

supported by any sponsored research funding from commercial or other entities. MIT, where the 

authors are employed, receives funds from numerous industrial and government sources, but the 

work on this paper received no such funding.
8

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Evidence and Implications. Environmental Science & Technology, 46: 5688–5695.
1

APPENDIX1

Contents

A1. SHALE GAS PRODUCTION GROWTH IN THE UNITED STATES..............................1

A2. VARIABILITY IN SHALE WELL PRODUCTION PERFORMANCE ............................1

A3. GHG INTENSITY OF FLOWBACK GAS HANDLING METHODS ...............................5

A4. ECONOMIC MOTIVATION FOR FLOWBACK GAS CAPTURE IN SHALE PLAYS..9

A5. REFERENCES...................................................................................................................13

A1. SHALE GAS PRODUCTION GROWTH IN THE UNITED STATES

Natural gas production in the United States has undergone a renaissance over the past 5–6 

years as a result of shale gas (Deutch, 2011). Between 2005 and 2010 the contribution from shale 

gas to total U.S. marketed gas production rose from less than 2% to more than 20%. Based upon 

EIA data, 2011 has set an all time record for U.S. production as the result of shale gas growth, 

with total daily dry output for the first ten months of the year averaging 1.77 Gm3/day (62.7 

Bcf/day). 

The remarkable shale gas production levels seen over the past number of years have been 

supported by a relatively small number of plays, the main ones being the Barnett shale, in Texas’ 

Fort Worth basin, the Fayetteville and Woodford shales of the Arkoma basin in Arkansas and 

Oklahoma, the Haynesville shale on the Texas Louisiana boarder, the Marcellus shale in the 

Appalachian basin, and of late the Eagle Ford shale located in southwest Texas. Figure A1

illustrates the growth in gas output from these shale gas plays since 2000. Until 2009 the 

overwhelming majority of total U.S. shale gas production came from the Barnett shale; however, 

in the last two years that situation has changed and production from other plays, particularly the 

Haynesville and Marcellus is now growing rapidly.

A2. VARIABILITY IN SHALE WELL PRODUCTION PERFORMANCE

The shale plays currently being developed in the U.S. do not constitute a homogenous 

resource. Each play has its own set of particular geological, geo-mechanical, geo-chemical and 

petrophysical characteristics, and variability in factors including reservoir pressure, total organic 

content, thermal maturity, porosity, the presence of natural fractures along with a lack of 

knowledge regarding shale rocks’ fundamental production mechanisms means that the 

performance of individual wells can differ substantially both within and between plays (Jarvine 

et al., 2007; Curtis et al., 2012; Hammes et al., 2011; Baihly et al., 2012).Two metrics widely 

used in describing shale well performance are the initial production (IP) rate and the production 

decline rate. Together these combine to determine the ultimate recovery (UR) from a well.

The IP rate variability among horizontal wells brought on production in the five most active 

U.S. shale gas plays in 2010 is given in Table A1. Reviewing the data in the table reveals the 

 

1

This is an appendix to O’Sullivan and Paltsev (2012): Shale Gas Production: Potential versus Actual GHG

Emissions, MIT Joint Program on the Science and Policy of Global Change Report 230

(http://globalchange.mit.edu/files/document/MITJPSPGC_Rpt230.pdf)
2

extent of both the intra and inter-play well-to-well IP rate variability. In each play the P80 IP 

rates are 2–3X the P20 rates, while between plays the mean IP rates vary by up to 4.3X. Similar 

trends can also be observed in IP rate data for prior years. 

0

50

100

150

200

250

300

350

400

450

Gas production: 

Mm3/day

Eagle Ford

Marcellus

Haynesville

Woodford

Fayetteville

Barnett

Figure A1. Growth in natural gas production from U.S. shale plays between 2000 and 2010

(Source: HPDI, 2012).

Table A1. IP rate variability of the horizontal wells brought on production during 2010 in 

the Barnett, Fayetteville, Haynesville, Woodford and Marcellus shale plays (Source: Authors’ 

calculations based on HPDI, 2012).

IP Rate: 1x103 m3/day

Shale Play # of H. Wells Mean P80 P50 P20

Barnett 1,785 60.6 85.5 52.1 30.6

Fayetteville 870 65.7 90.8 63.4 37.1

Haynesville 509 261.5 339.6 246.2 167.5

Woodford 208 108.1 152.3 91.7 51.2

Marcellus 576 90.0 127.4 76.1 43.3

The Barnett shale play provides an excellent basis for examining this year-to-year IP rate 

variability due to its relatively longer production history and larger inventory of well. Figure A2

plots the IP rate cumulative probability functions for each vintage of horizontal wells drilled in 

the Barnett from 2005 to 2010. Each vintage displays the well-to-well IP rate variability 

described above, however, it is also clear that the on average, IP rates have been increasing 

incrementally year-on-year. In 2005, the mean, P90 and P10 IP rates for the 720 horizontal wells 

that were brought on production were 48,500, 93,050 and 14,300 m3/day respectively. By 2010 

those same figures had increased to 60,700, 110,900 and 21,500 m3/day. Many factors play a role 
3

in this IP rate shift; however, increased horizontal well lengths and more effective fracturing are 

likely to be some of the most important.

Figure A2. Cumulative probability functions for initial production rates of horizontal wells 

drilled in the Barnett shale from 2005 to 2010 (Source: HPDI, 2012).

The rate at which a well’s gas production changes over time is described by the well’s decline 

characteristic or “type curve.” Data on shale well decline characteristics is still sparse due to the 

limited time most wells have been producing. However, the data that is available reveals some 

interesting trends. The first is that in general, shale well output tends to drop by 60% or more 

from the IP rate level over the first 12 months. The second is that the available longer-term 

production data suggests that levels of production decline in later years are moderate, often less 

than 20% per year. Figure A3 shows the normalized decline characteristics for each vintage in 

the Barnett shale from 2005 to 2010. Although there is some variation, overall, the normalized 

decline characteristics have been very similar year-to-year.

All the shale plays currently in production have qualitatively similar decline characteristics, 

i.e. significant production decline during the first year of production followed by more moderate 

rates of decline in subsequent years. Nonetheless, there are meaningful differences between plays 

as shown in Figure A4, which plots the normalized 2009 decline characteristics of the Barnett, 

Fayetteville and Haynesville plays. The Barnett and Fayetteville plays have relatively similar 

year 1 decline rates of 55–60%. 
4

0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0.9

1

0 12 24 36 48 60 72 84

Normalized 

Production Rate

Months

2005

2006

2007

2008

2009

2010

Figure A3. Normalized production decline characteristics for Barnett shale well vintages 

from 2005 to 2010 (Source: HPDI, 2012).

Figure A4. Normalized production decline characteristics for 2009 vintage horizontal wells 

in the Barnett, Fayetteville and Haynesville shale plays (HPDI, 2012).

The Haynesville decline characteristic is different, with a year 1 production rate decline of 

~75%. Understanding the differences in decline characteristics among shale plays is very 

complex and requires consideration of both reservoir and well completion factors. However, 
5

insights do exist regarding the variability. For example, in the case of the Haynesville, its very 

high year 1 decline rates have been linked to the highly over-pressured nature of the reservoir 

and the likelihood of pressure dependent permeability resulting in a temporally progressive 

reduction in gas conductivity (Thompson et al., 2010; Baihly et al., 2010).

Determining how much gas individual shale wells will produce over their lifetime is also a 

challenging problem muddied by many uncertainties. To date, estimates of shale well UR have 

been made by combining IP rate data with long-term projections of well production decline 

characteristics. These decline projections are often extrapolated from shorter-term decline data 

shown in Figures A3 & A4. These “type curve” methods for estimating shale well UR are 

controversial as they are based on techniques developed to assess the UR from wells in reservoir 

boundary dominated flow regimes (Lee et al., 2010; Anderson et al., 2010). The complexity of 

these issues is beyond the scope of this paper; however, one outcome is that the fitting of shale 

well decline rate data has in some instances yielded parameters outside the limits suggested as 

reasonable by the theory, and the practical result of this is that UR estimates based on these type 

curve methods must be viewed with some caution, particularly in terms of possible 

overestimation (Lee et al., 2010). Nonetheless, until more data becomes available, the use of 

type curves at least for aggregate qualitative analysis is not unreasonable. UR estimates based on 

the type curve method for the 2010 vintage of horizontal wells in the major U.S. shale plays are 

given in Table A2. These URs were calculated assuming both a 30-year well production 

lifetime, and a more conservative 15-year well lifetime. A 30-year well producing lifetime is 

widely assumed, particularly by the industry, when estimating shale well UR.

Table A2. Projected horizontal well URs for the major U.S. shale plays based on 2010 well 

IP rate data assuming 30-year and 15-year production lifetimes (Source: Authors’ 

calculations based on HPDI 2012).

Estimated UR: 1x106 m3 (30/15 year estimates)

Shale Play Mean P80 P50 P20

Barnett 70.8 / 50.9 99.1 / 73.6 59.4 / 45.3 36.8 / 25.5

Fayetteville 76.4 / 56.6 104.7 / 76.4 73.6 / 53.8 45.5 / 31.1

Haynesville 150.0 / 118.9 192.4 / 155.7 141.5 / 113.2 96.2 / 76.4

Woodford 124.5 / 93.4 175.5 / 130.2 107.5 / 79.2 59.4 / 42.45

Marcellus 104.7 / 76.4 147.2 / 107.6 87.7 / 65.1 50.9 / 36.8

A3. GHG INTENSITY OF FLOWBACK GAS HANDLING METHODS

Knowing how gas produced during flowback is handled is necessary to evaluate the actual 

fugitive emissions from shale well hydraulic fracturing operations. Broadly speaking, three 

handling options exists; the gas can be vented directly to the atmosphere, it can be flared, or it 

can be captured and routed to a pipeline. This final process is often referred to as “reduced 

emissions completion” or “green completion.” Of the three methods, venting has the highest 

GHG intensity, with every 1 m3of gas vented resulting in 0.788 m3of methane emissions (EPA, 
6

2010). Flaring, when executed correctly is 98% efficient, thus resulting in 0.01–0.02 m3of 

methane emissions per m3of natural gas flared (EPA, 2010). Gas capture have the potential to 

completely eliminate any methane or CO2 emissions resulting from flowback; however, in 

practice this is probably not achievable. Data from the EPA suggests that green completions 

result in the capture of at least 90% of potential methane emissions (EPA, 2010). This is likely 

an underestimation of the gas captured during well-executed green completions; however, we 

use it for analysis purposes in this paper.

The specific GHG emissions factors of the three gas handling techniques are given in Table 

A3. These factors were calculated assuming natural gas is composed of 78.8% methane by 

volume (EPA, 2010). The GHG impact of other constituent gases was ignored. This is a clear 

simplification particularly considering natural gas often contains some volumes of CO2; 

however, it is consistent with the EPA’s own methodology and that used by others carrying out 

similar analysis (Hultman et al., 2011). The methane contribution was converted into CO2e using 

both 100- and 20-year methane global warming potentials (GWPs) of 25 and 72 respectively 

(Solomon et al., 2007). Calculations using both the standard 100-year GWP and the 20-year 

GWP are shown in order to acknowledge the debate currently occurring regarding which factor 

should be used when assessing the GHG emissions impacts of natural gas production and use 

(Howarth et al., 2011a; Howarth et al., 2011b, Cathles et al., in press). A concise summary of the 

underlying scientific analysis that is cited as part of this debate is provided by Hultman (Hultmen 

et al., 2011) and concludes that there exists, reasonable alternative perspectives on the issue. The 

specific emission factors reported in Table A3 reveal the very dramatic impact that assumptions 

regarding how gas produced during flowback is handled can have on the analysis of GHG 

footprints. When assuming a 100-year GWP for methane, the difference in the emission factors 

of cold-venting and green completions is an order of magnitude. Assuming a 20-year GWP, 

flaring becomes the least GHG intensive method of handling flowback gas.

Table A3. Calculation of emission factors for gas handling techniques, which can be 

deployed during shale well flowback operations assuming both 100 and 20-year global 

warming potentials (GWP) (Source: Authors’ calculations).

Venting Flaring Gas Capture

CH4 emitted:

kg/1x103 m3of NG 537.5 10.8 53.8

CO2 emitted:

kg/1x103 m3of NG – 1,445.1 –

Total emissions factor (100-yr GWP):

kg CO2e/1x103 m3of NG 13,438 1,714 1,344

Total emissions factor (20-yr GWP):

kg CO2e/1x103 m3of NG 38,701 2,219 3,870

To date, attempts to analyze the GHG intensity of shale gas production have relied heavily on 

information from the U.S. EPA. In particular, EPA analysis that suggests a natural gas emissions 

factor of 9,175 Mcf per unconventional well completion or workover is widely cited (INGAA, 
7

2008). In this context the term “emissions factor” is misleading. The 9,175 Mcf figure is the 

EPA’s quantification of the volume of natural gas produced during flowback, i.e. the potential 

emissions, not the actual emissions. The authors suggest that the EPA revise their terminology in 

future publications and refer to this value as “potential emissions” in order to minimize 

confusion. As a quantification of “potential emissions” the 9,175 Mcf, or 259,836 m3 of natural 

gas per completion appears reasonable, at least in qualitative terms. In comparison to the perwell potential emissions estimates in Table 1, the EPA figure is slightly lower than that for a 

2010 mean performance well in the Barnett shale. This would be expected as the EPA figure is 

derived from data that included not just shale wells, but also lower performance unconventional 

wells.

The EPA is opaque with regards to defining how potential emissions are handled. This is 

understandable due to the lack of hard data; however, the agency does attempt to provide some 

directional guidance. For the purposes of estimating emissions from 2007 U.S. gas well 

completions and workovers, it assumes that 51% of the gas produced during well flowback is 

flared and 49% is vented (EPA, 2010). This breakdown is based upon regulation in place in four 

sample states; Texas, New Mexico, Oklahoma and Wyoming. A 2008 INGAA report (INGAA, 

2008) estimated that if a more representative set of states were considered, then the proportion of 

flowback gas that would require flaring by regulation would fall from 51% to 15%. However, 

regulation is only part of the gas-handling picture. This is illustrated by the fact that in those 

states without a mandatory flaring requirement in the EPA’s four state analysis, ~70% of the gas 

produced during flowback was not vented, but in fact captured by green completion operations 

(EPA, 2011). Additionally, an unknown, but likely similar proportion of the gas produced where 

flaring was required (as a minimum control) is also likely to have been captured. The reason for 

this is economic incentive. Where capture is possible due to infrastructure availability, the 

marginal cost of the process itself is low and operators generate value by doing it. A detailed 

discussion of green completion economics will be presented in section A4.

The contention that real-world flowback gas handling practices differ appreciably from what 

regulation alone demands is supported by the results of a 2011 American Natural Gas Alliance 

(ANGA) survey (Thompson et al., 2010) of field practice. This survey recorded the gas handling 

approaches used by 8 exploration and production companies across a representative set of U.S. 

unconventional gas (both shale and tight sands) plays. A total of 1,578 wells were included in the 

survey. Of these wells, gas was captured during flowback from 1,475 or 93%, 56 wells were 

flared and 47 wells were vented. Of course the fact that these results are the product of an 

industry sponsored survey means they are open to question, however, the survey does represent 

the only large-scale publically reported assessment of current gas handling field practice 

available. In preparing this paper the authors had extensive discussions with industry, EPA and 

other relevant groups regarding actual field practice. We have concluded that a reasonable 

representation of contemporary flowback gas handling field practice in U.S. shale plays would 

comprise 70% of wells using reduced emissions completions, 15% being flared and 15% being 

vented (EPA, 2012b).
8

Table A4. Specific GHG intensities for five flowback gas handling scenarios assuming 100 

year and 20 Year CH4 global warming potentials (GWP) (Source: Authors’ calculations).

Flowback GHG intensity: kg CO2e/m3 of NG 100-Year GWP 20-Year GWP

Scenario 1: 100% vented 13.44 38.70

Scenario 2: 15% flared, 85% vented 11.68 33.23

Scenario 3 51% flared, 49% vented 7.46 20.10

Scenario 4: 93% GC, 4% flared, 3% vented 1.72 4.85

Scenario 5—“Current Field Practice”: 

70% capture, 15% flared, 15% vented 3.21 8.85

To illustrate how assumptions regarding gas handling impact on the GHG intensity of shale 

gas-related hydraulic fracturing we take the potential emissions data from Tables 1 & 2, and 

calculate the associated actual emissions assuming five gas handling scenarios (Deutch, 2011); 

all potential emissions are vented as assumed in (Howarth et al., 2011a; Jacoby et al., 2012), a 

case where 15% of gas is flared and the remainder is vented per (INGAA, 2008; IEA, 2012), the 

regulatory case where 51% of gas is flared and the remainder is vented per EPA; (4) the ANGA 

survey case with 93% capture, 4% flared and 3% vented, and (5), a “current field practice” case, 

with 70% capture, 15% flared and 15% vented. Table A4 shows the GHG intensities in kg 

CO2e/m3associated with each of the gas handling cases assuming both a 100-year and 20-year 

GWP factor for CH4

Table A5. Mean per-well actual emissions from shale well hydraulic fracturing operations in 

2010 (Source: Authors’ calculations based on HPDI 2012).

Barnett Fayetteville Haynesville Marcellus Woodford

Per-well GHG intensity: Mg CO2e/well (100 year CH4 GWP)

100% vented 3668.5 3977.6 15816.4 5442.3 6544.2

15% flared, 85% vented 3188.4 3457.1 13746.5 4730.1 5687.8

51% flared, 49% vented 2036.2 2207.8 8778.8 3020.7 3632.4

ANGA Survey 469.9 509.5 2026.1 697.2 838.3

Current field practice 877.3 951.2 3782.2 1301.4 1564.9

Per-well GHG intensity: Mg CO2e/well (20 year CH4 GWP)

100% vented 10565.4 11455.5 45551.1 15673.9 18847.4

15% flared, 85% vented 9071.5 9835.7 39110.3 13457.6 16182.4

51% flared, 49% vented 5486.0 5948.2 23652.1 8138.6 9786.4

ANGA Survey 1323.8 1435.3 5707.3 1963.8 2361.5

Current field practice 2415.3 2618.7 10413.0 3583.1 4308.5

The specific GHG intensities shown in Table A4 reveal the importance of gas handling 

assumptions. There is 7.8X difference in intensity depending upon whether you assume all 

potential emissions are vented (Scenario 1), or handled according to the ANGA survey (Scenario 

4) assuming a 100 year CH4 GWP. Coupling the specific GHG intensity factors in Table A4 with 

the volumes of potential emissions from Tables 1 & 2 enables the evaluation of actual emissions 
9

associated with shale well flowback in 2010 for different gas handling scenarios. The per-well 

actual emissions are shown in Table A5, with the aggregate actual emissions in Table A6.

Table A6. Total actual emissions from 2010 shale well hydraulic fracturing operations.

(Source: Authors’ calculations based on HPDI, 2012)

Barnett Fayetteville Haynesville Marcellus Woodford Total

Total GHG intensity: Tg CO2e (100 year CH4 GWP)

100% vented 6.5 3.5 8.1 3.1 1.4 23

15% flared, 85% 

vented 5.7 3.0 7.0 2.7 1.2 20

51% flared, 49% 

vented 3.6 1.9 4.5 1.7 0.8 13

ANGA Survey 0.8 0.4 1.0 0.4 0.2 3

Current field 

practice 1.6 0.8 1.9 0.7 0.3 5

Total GHG intensity: Tg CO2e (20 year CH4 GWP)

100% vented 18.9 10.0 23.2 9.0 3.9 65

15% flared, 85% 

vented 16.2 8.6 19.9 7.8 3.4 56

51% flared, 49% 

vented 9.8 5.2 12.0 4.7 2.0 34

ANGA Survey 2.4 1.2 2.9 1.1 0.5 8

Current field 

practice 4.3 2.3 5.3 2.1 0.9 15

A4. ECONOMIC MOTIVATION FOR FLOWBACK GAS CAPTURE IN SHALE PLAYS

As shown in Table A4, the gas handling methods used to during flowback have a dramatic 

impact on the GHG intensity of the process. Because of the volumes of gas involved, particularly 

in the case of contemporary shale wells, the extensive or exclusive use of venting would results 

in the process having a very high GHG intensity. By contrast, the extensive use of flaring and 

particularly capture result in much more benign emission levels; however, both flaring and 

capture are not without their operation challenges. Capture in particular requires gas gathering 

facilities to be present at the well pad during flowback, something that is not always practical.

Traditionally, gas exploration and development involved an appreciable amount of trial and 

error or “wildcatting,” whereby single or small numbers of wells were drilled in a prospective 

area without a high level of certainty that those wells would ultimately prove to be commercial. 

With this approach gas gathering systems would only be built after a well was completed. As a 

result capture was rarely practical or necessary for that matter as fracturing was less widely used. 

Contemporary shale gas development takes place in a very different manner. Often described as 

a “manufacturing process,” shale plays are developed in a relatively systematic manner made 

possible by the extensive and contiguous nature of the producing formations, and the relative 

assurance that any given well will produce gas. This relative a priori assurance regarding 

production coupled with the fact that multi-well pads (often six or more well being drilled 
10

horizontally from one surface location) are now standard practice means that gathering 

infrastructure is in many cases being built in parallel or even ahead of actual well drilling and 

hydraulic fracturing operations.

Operators in shale plays have a significantly higher economic incentive to have gathering 

facilities in place as wells are being completed than is the case in conventional plays. The 

assurance that the well will most likely produce gas means that by having gathering available as 

soon as a well is ready to go online saves the operators the carry costs associated with a 

completed but stranded well, and this boosts the present value of any given well. Furthermore, 

having gathering facilities in place also enables operators market the significant volumes of gas 

that will be produced during flowback. This is important as it means that producers are 

financially incentivized to minimize fugitive emissions. 

The current debate regarding the GHG intensity of flowback operations has relied heavily on 

assumptions regarding regulation. Considering regulation is of course necessary in any such 

analysis; however, it is not sufficient. To fully assess the situation, one must also consider the 

economics of the relevant gas handling techniques, as seen from the gas operators’ perspective. 

Both venting and flaring destroy value. Clearly though, if the present value of these approaches 

is higher (or less negative) than capturing the gas they will be chosen. For low performance 

unconventional tight sands wells it is certainly possible that the typical volumes of gas produced 

during flowback are too small to warrant gas capture. However, in the case of contemporary 

shale wells the situation is entirely different. Table A7 shows the mean per-well and total value 

of gas produced during shale well flowback operations in 2010 assuming a conservatively low 

long-term gas price of $4.00/Mcf ($141.24 per thousand m3) (MIT, 2011).

Table A7. Gross value potential of gas produced during flowback operations in the major 

U.S. shale plays during 2010 (Source: Authors’ calculations).

Barnett Fayetteville Haynesville Marcellus Woodford All Plays

Per-well value: $k 38.6 41.8 166.2 57.2 68.8 –

# of horizontal wells 1,785 870 509 576 208 3,948

Total value: $M 68.8 36.4 84.6 32.9 14.3 237.1

Overall, more than $237 million dollars-worth of gas was produced during shale well 

flowback operations in 2010, or just over $60,000 of gas per well. These are significant cash 

flows and their importance to the overall economics of an individual well should not be 

overlooked, particularly as these cash flows occur in year 0 and so are not subject to any timevalue-of-money discounting. Of course gas capture is not free, and the costs must be included in 

the analysis. These authors define the cost of gas capture as the amortized capital cost along with 

operating costs, or more typically the rental costs of a green completion separator unit and 

accompanying crew. These units are in essence very high capacity versions of the multi-phase 

separation systems that are permanently installed at producing well. They are specifically 

designed to handle the much higher volumes of water and solids that flow during flowback and 
11

are typically skid or trailer mounted. The costs of gas gathering infrastructure are not considered 

in the assessment of the gas capture economics. These facilities are a sunk cost as they must be 

in place to get gas to market regardless of whether flowback gas captured, vented or flared.

The cost of green completion services differs somewhat by play due to the different 

equipment specifications needed to handle differing levels of flowback. Devon Energy reports a 

per-well per-day cost of $1,000 for green completion services in the Barnett shale (EPA, 2010). 

This figure is reasonable, and also representative of the costs in the Fayetteville shale. 

Correspondence with operators in the higher performance plays such as the Marcellus shale have 

indicated that flowback gas capture costs of between $2,000 and $3,000 per-well per-day. To 

establish a conservative estimate of the value generation potential of gas capture, slightly higher 

per-well per-day capture costs were assumed. $2,000 for the Barnett and Fayetteville shales, 

$3,000 for the Marcellus and Woodford plays and $6,000 for the very high volume wells in the 

Haynesville. Coupling these costs with the gross revenue figures from Table A7 enables the net 

value potential of green completions to be calculated. The results of this are shown in Table A8.

Table A8. Net value potential of gas produced during flowback operations in the major U.S. 

shale plays during 2010 (Source: Authors’ calculations).

Barnett Fayetteville Haynesville Marcellus Woodford All Plays

Per-well gross revenue:

$k

$38.6 $41.8 $166.2 $57.2 $68.8 –

Per-well capture cost:

$k $18.0 $18.0 $54.0 $27.0 $27.0 –

Per-well net value of 

capture:

20.6 23.8 112.2 30.2 41.8 –

# of horizontal wells 1,785 870 509 576 208 3,948

Total net value potential

of gas capture: $M $36.7 $20.7 $57.1 $17.4 $8.7 $140.6

The results in Table A8 show that gas capture generates value in all plays. For an average 

well in most shale plays the net additional value will be anywhere from $20,000 to $40,000. In 

the Haynesville the net value per well of capture will be over $100,000. Given 2010 activity 

levels, the total net value of gas capture is just over $140 million. As discussed earlier, it is not 

practical to expect the use of green completion techniques on 100% of shale wells; however, 

assuming that 70% of shale wells are green completed, this still represents almost $100 million 

dollars in annual value generation as $4.00/Mcf gas. The preceding analysis of gas capture 

economic attractiveness makes a number of assumptions, albeit reasonable ones regarding the 

wellhead gas price and the cost of capture. Sensitivity analysis on these variables provides 

further insight. Figures 5 shows what percentage of the 2010 Barnett well population would 

yield positive net revenue from gas capture assuming the cost of the completions was $1,000, 

$2,000 and $3,000 dollars per day for a 9 day flowback period, at $4.00/Mcf wellhead gas price.
12

At the $1,000 per day green completion cost quoted by Devon Energy (21), 95% of wells 

generated positive net revenue, i.e. the value of the gas captured and sold was more than the cost 

of capture. At our more conservative $2,000 per day case 83% of all wells still generated positive 

revenue, and even assuming a very high cost of $3,000 per day, 64% of wells generated positive 

net revenues. Figure A6 shows the impact of varying gas price on the green completion 

economics of the same wells assuming a fixed completion cost of $2,000 per day. 

Figure A5. Percentage of 2010 Barnett shale wells for which gas capture yields positive and 

negative net revenues assuming a wellhead gas price of $4.00/Mcf and gas capture 

costs of $1,000, $2,000 and $3,000 per day (Source: Authors’ calculations).

Figure A6. Percentage of 2010 Barnett shale wells for which gas capture yields positive and 

negative net revenues assuming wellhead gas prices of $2.00/Mcf, $4.00/Mcf and 

$6.00/Mcf and a capture cost of $2,000 per day for a 9 day flowback period. (Source: 

Authors’ calculations).

At $2.00/Mcf, 44% of the wells generate positive revenue, while at $6.00/Mcf, 92% of the 

wells were in the black. An important point to note is that although natural gas prices in the U.S. 

during late 2011 and early 2012 have been between $2.50–3.00/Mcf range, these prices are not 

indicative of the likely long-term equilibrium price in the U.S. market. The 2011 EIA Annual 

Energy Outlook (U.S. EIA, 2011) projects wellhead gas prices of over the coming 5 year to be in 

the $4.00–$4.50/Mcf range, while the 2011 MIT Future of Natural Gas study (MIT, 2011), 
13

projects gas prices over the same period to be in the $5.00–$5.50/Mcf range. Given these 

projections, we feel that the use of a $4.00/Mcf assumption in the economic analysis of green 

completions is conservative.

The results of the sensitivities shown in Figures A5 and A6 reiterate the point that shale well 

flowback gas capture is economically attractive to operators. This is so for the vast majority of 

well even in lower performance shale plays like the Barnett, and even under higher than 

reasonable costs and lower than likely gas price scenarios.

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REPORT SERIES of the MIT Joint Program on the Science and Policy of Global Change

Contact the Joint Program Office to request a copy. The Report Series is distributed at no charge.

FOR THE COMPLETE LIST OF JOINT PROGRAM REPORTS: 

http://globalchange.mit.edu/pubs/all-reports.php

189. Modeling the Global Water Resource System in an 

Integrated Assessment Modeling Framework: IGSMWRS Strzepek et al. September 2010

190. Climatology and Trends in the Forcing of the 

Stratospheric Zonal-Mean Flow Monier and Weare

January 2011

191. Climatology and Trends in the Forcing of the 

Stratospheric Ozone Transport Monier and Weare

January 2011

192. The Impact of Border Carbon Adjustments under 

Alternative Producer Responses Winchester February 

2011

193. What to Expect from Sectoral Trading: A U.S.-China 

Example Gavard et al. February 2011

194. General Equilibrium, Electricity Generation 

Technologies and the Cost of Carbon Abatement Lanz 

and Rausch February 2011

195. A Method for Calculating Reference 

Evapotranspiration on Daily Time Scales Farmer et al. 

February 2011

196. Health Damages from Air Pollution in China 

Matus et al. March 2011

197. The Prospects for Coal-to-Liquid Conversion: 

A General Equilibrium Analysis Chen et al. May 2011

198. The Impact of Climate Policy on U.S. Aviation 

Winchester et al. May 2011

199. Future Yield Growth: What Evidence from Historical 

Data Gitiaux et al. May 2011

200. A Strategy for a Global Observing System for 

Verification of National Greenhouse Gas Emissions

Prinn et al. June 2011

201. Russia’s Natural Gas Export Potential up to 2050

Paltsev July 2011

202. Distributional Impacts of Carbon Pricing: A General 

Equilibrium Approach with Micro-Data for Households

Rausch et al. July 2011

203. Global Aerosol Health Impacts: Quantifying 

Uncertainties Selin et al. August 201

204. Implementation of a Cloud Radiative Adjustment 

Method to Change the Climate Sensitivity of CAM3

Sokolov and Monier September 2011

205. Quantifying the Likelihood of Regional Climate 

Change: A Hybridized Approach Schlosser et al. October 

2011

206. Process Modeling of Global Soil Nitrous Oxide 

Emissions Saikawa et al. October 2011

207. The Influence of Shale Gas on U.S. Energy and 

Environmental Policy Jacoby et al. November 2011

208. Influence of Air Quality Model Resolution on 

Uncertainty Associated with Health Impacts Thompson 

and Selin December 2011

209. Characterization of Wind Power Resource in the 

United States and its Intermittency Gunturu and 

Schlosser December 2011

210. Potential Direct and Indirect Effects of Global 

Cellulosic Biofuel Production on Greenhouse Gas 

Fluxes from Future Land-use Change Kicklighter et al.

March 2012

211. Emissions Pricing to Stabilize Global Climate Bosetti et al.

March 2012

212. Effects of Nitrogen Limitation on Hydrological 

Processes in CLM4-CN Lee & Felzer March 2012

213. City-Size Distribution as a Function of Socio-economic 

Conditions: An Eclectic Approach to Down-scaling Global 

Population Nam & Reilly March 2012

214. CliCrop: a Crop Water-Stress and Irrigation Demand 

Model for an Integrated Global Assessment Modeling 

Approach Fant et al. April 2012 

215. The Role of China in Mitigating Climate Change Paltsev 

et al. April 2012

216. Applying Engineering and Fleet Detail to Represent

Passenger Vehicle Transport in a Computable General 

Equilibrium Model Karplus et al. April 2012

217. Combining a New Vehicle Fuel Economy Standard with

a Cap-and-Trade Policy: Energy and Economic Impact in 

the United States Karplus et al. April 2012

218. Permafrost, Lakes, and Climate-Warming Methane 

Feedback: What is the Worst We Can Expect? Gao et al. May 

2012

219. Valuing Climate Impacts in Integrated Assessment

Models: The MIT IGSM Reilly et al. May 2012

220. Leakage from Sub-national Climate Initiatives: The Case 

of California Caron et al. May 2012

221. Green Growth and the Efficient Use of Natural Resources 

Reilly June 2012

222. Modeling Water Withdrawal and Consumption for 

Electricity Generation in the United States Strzepek et al.

June 2012

223. An Integrated Assessment Framework for Uncertainty 

Studies in Global and Regional Climate Change: The MIT 

IGSM Monier et al. June 2012

224. Cap-and-Trade Climate Policies with Price-Regulated 

Industries: How Costly are Free Allowances? Lanz and 

Rausch July 2012.

225. Distributional and Efficiency Impacts of Clean and 

Renewable Energy Standards for Electricity Rausch and 

Mowers July 2012.

226. The Economic, Energy, and GHG Emissions Impacts of 

Proposed 2017–2025 Vehicle Fuel Economy Standards in 

the United States Karplus and Paltsev July 2012

227. Impacts of Land-Use and Biofuels Policy on Climate: 

Temperature and Localized Impacts Hallgren et al. August 

2012

228. Carbon Tax Revenue and the Budget Deficit: A Win-WinWin Solution? Sebastian Rausch and John Reilly August 2012

229. CLM-AG: An Agriculture Module for the Community 

Land Model version 3.5 Gueneau et al. September 2012

230. Quantifying Regional Economic Impacts of CO2

Intensity Targets in China Zhang et al. September 2012

231. The Future Energy and GHG Emissions Impact of 

Alternative Personal Transportation Pathways in China 

Kishimoto et al. September 2012

232. Will Economic Restructuring in China Reduce TradeEmbodied CO2

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233. Climate Co-benefits of Tighter SO2 and NOx Regulations 

in China Nam et al. October 2012

234. Shale Gas Production: Potential versus Actual GHG 

Emissions O’Sullivan and Paltsev November 2012