Shale gas production: potential versus actual greenhouse gas emissions

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IOP PUBLISHING ENVIRONMENTAL RESEARCH LETTERS

Environ. Res. Lett. 7 (2012) 044030 (6pp) doi:10.1088/1748-9326/7/4/044030

Shale gas production: potential versus

actual greenhouse gas emissions

Francis O’Sullivan1 and Sergey Paltsev1,2

1 MIT Energy Initiative, Massachusetts Institute of Technology, 77 Massachusetts Avenue, Cambridge,

MA 02139, USA

2 MIT Joint Program on the Science and Policy of Global Change, Massachusetts Institute of

Technology, 77 Massachusetts Avenue, Cambridge, MA 02139, USA

E-mail: frankie@mit.edu

Received 25 June 2012

Accepted for publication 7 November 2012

Published 26 November 2012

Online at stacks.iop.org/ERL/7/044030

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

4000 horizontal shale gas wells brought online that year are 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

emission ‘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 Gg CH4, 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.

Keywords: shale gas, hydraulic fracturing, GHG emissions, fugitive emissions, reduced

emission completions

S Online supplementary data available from stacks.iop.org/ERL/7/044030/mmedia

1. Introduction

Over the past decade, economically recoverable shale gas has

transformed the US natural gas industry, with some analysts

characterizing it as a ‘revolution’ (Deutch 2011, Jacoby et al

2012). With shale driven growth, the US 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

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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,

2011b, 2012), and uncertainty in estimates of the resource

scale (Jacoby et al 2012, Urbina 2011, MIT 2011, Lee and

Sidle 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.

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

+06$33.00 11748-9326/12/044030 
c 2012 IOP Publishing Ltd Printed in the UK
Environ. Res. Lett. 7 (2012) 044030 F O’Sullivan and S Paltsev

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, 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 and Clavin (2012) suggest they are

approximately equal, while Jiang et al (2011) and Stephenson

et al (2011) both conclude that shale gas has a lifetime GHG

impact that is slightly higher than that of conventional gas. All

of these groups do however conclude that the GHG impact

of 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 day

flowback 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) show 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 3948

horizontally drilled shale gas wells brought online in the

US 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. 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 S1 of the supplementary materials (available

at stacks.iop.org/ERL/7/044030/mmedia). The variation in

initial well productivity within and between the shale plays is

driven in large part by underlying geological, geo-mechanical,

geochemical 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

2
Environ. Res. Lett. 7 (2012) 044030 F O’Sullivan and S Paltsev

Table 1. Per-well hydraulic fracturing-related potential fugitive emissions from 2010 vintage US horizontal shale gas wells. (Source:

authors’ calculations based on HPDI 2012.)

Per-well potential

emissions: (1 × 103 m3

natural gas) Barnett Fayetteville Haynesville Marcellus Woodford

Mean: 273 296 1177 405 487

P80: 385 409 1538 573 685

P50: 234 285 1108 342 413

P20: 138 167 754 195 230

Table 2. Total hydraulic fracturing-related potential fugitive emissions from US 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: (1 × 103 m3 of natural gas)

273 296 1177 405 487 —

No. of horizontal wells 1785 870 509 576 208 3948

Total potential fugitive emissions:

(1 × 106 m3 of natural gas)

487 257 599 234 101 1678

Total potential fugitive methane emissions:

(Gg CH4 )

262 138 322 125 54 902

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 yr and 15 yr producing lifetimes. (Source: authors’ calculations based on HPDI 2012.)

Barnett

(%)

Fayetteville

(%)

Haynesville

(%)

Marcellus

(%)

Woodford

(%)

30 yr lifetime 0.39 0.39 0.78 0.39 0.39

15 yr lifetime 0.54 0.52 0.99 0.53 0.52

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 6002

Gg CH4.

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 and Sidle 2010). To account for this

uncertainty we assume two well production lifetimes in this

analysis; the commonly assumed 30 yr lifetime, and a more

conservative 15 yr 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 yr 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 yr 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

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 over-pressured reservoir (Baihly et al 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 S2 of the

supplementary materials (available at stacks.iop.org/ERL/7/

044030/mmedia).

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 gas-related 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 yr

Global Warming Potential (GWP) for CH4. Shindell et al

(2009) argue that the use of a 100 yr integration period

underestimates the actual warming impact of CH4 and

suggests that a higher GWP factor, based on a 20 yr

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 IPCC (2007) provides this

3
Environ. Res. Lett. 7 (2012) 044030 F O’Sullivan and S Paltsev

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

factor for 20-, 100-, and 500 yr integration periods and uses

100 yr GWPs. MIT (2011) argues that 20 yr 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 yr GWP for CH4 are detailed in section S3 of the

supplementary materials (available at stacks.iop.org/ERL/7/

044030/mmedia).

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 (one

referee of this paper pointed out an oral presentation

given at the 2012 Goldschmidt International Geochemistry

Conference in Montreal where gas insiders stressed this point

and argued that venting of methane is a common practice since

flaring draws public attention). 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 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, 2012a); however,

it does not separate fugitive emissions 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 S3 of

the supplementary materials available at stacks.iop.org/ERL/

7/044030/mmedia.) 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 4638 Mg CH4/well (6800 000

m3 CH4) for Haynesville, our mean estimates are 35.1 Mg

CH4/well and 151.3 Mg CH4/well, respectively.

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, 1040 m3 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 6800 000 m3 CH4. This is a

very considerable amount of gas and assuming a conservative

long-run 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 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 3948 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 S4 of the supplementary

materials available at stacks.iop.org/ERL/7/044030/mmedia).

If the cost of reduced emission completion is $1000 per day

as stated by Devon (2008), 95% of the 2010 Barnett wells

4
Environ. Res. Lett. 7 (2012) 044030 F O’Sullivan and S Paltsev

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, $2000 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

S5 and S6 of the supplementary materials (available at stacks.

iop.org/ERL/7/044030/mmedia).

4. Conclusions

Taking actual field practice into account, we estimate that

in 2010 the total fugitive GHG emissions from US shale

gas-related hydraulic fracturing amounted to 216 Gg CH4.

This represents 3.6% of the estimated 6002 Gg CH4 of

fugitive emissions from all natural gas production-related

sources in that year (EPA 2012a, 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, 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.

Acknowledgments

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.

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