We evaluate the greenhouse gas footprint of natural gas obtained by high-volume hydraulic fracturing from shale formations, focusing on methane emissions. Natural gas is composed largely of methane, and 3.6% to 7.9% of the methane from shale-gas production escapes to the atmosphere in venting and leaks over the life-time of a well. These methane emissions are at least 30% more than and perhaps more than twice as great as those from conventional gas. The higher emissions from shale gas occur at the time wells are hydraulically fractured—as methane escapes from flow-back return fluids—and during drill out following the fracturing. Methane is a powerful greenhouse gas, with a global warming potential that is far greater than that of carbon dioxide, particularly over the time horizon of the first few decades following emission. Methane contributes substantially to the greenhouse gas footprint of shale gas on shorter time scales, dominating it on a 20-year time horizon. The footprint for shale gas is greater than that for conventional gas or oil when viewed on any time horizon, but particularly so over 20years. Compared to coal, the footprint of shale gas is at least 20% greater and perhaps more than twice as great on the 20-year horizon and is comparable when compared over 100years. KeywordsMethane–Greenhouse gases–Global warming–Natural gas–Shale gas–Unconventional gas–Fugitive emissions–Lifecycle analysis–LCA–Bridge fuel–Transitional fuel–Global warming potential–GWP
Climatic Change
DOI 10.1007/s10584-011-0061-5
Methane and the greenhouse-gas footprint of natural
gas from shale formations
A letter
Robert W. Howarth ·Renee Santoro ·
Anthony Ingraffea
Received: 12 November 2010 / Accepted: 13 March 2011
© The Author(s) 2011. This article is published with open access at Springerlink.com
Abstract We evaluate the greenhouse gas footprint of natural gas obtained by high-
volume hydraulic fracturing from shale formations, focusing on methane emissions.
Natural gas is composed largely of methane, and 3.6% to 7.9% of the methane from
shale-gas production escapes to the atmosphere in venting and leaks over the life-
time of a well. These methane emissions are at least 30% more than and perhaps
more than twice as great as those from conventional gas. The higher emissions from
shale gas occur at the time wells are hydraulically fractured—as methane escapes
from flow-back return fluids—and during drill out following the fracturing. Methane
is a powerful greenhouse gas, with a global warming potential that is far greater
than that of carbon dioxide, particularly over the time horizon of the first few
decades following emission. Methane contributes substantially to the greenhouse
gas footprint of shale gas on shorter time scales, dominating it on a 20-year time
horizon. The footprint for shale gas is greater than that for conventional gas or oil
when viewed on any time horizon, but particularly so over 20 years. Compared to
coal, the footprint of shale gas is at least 20% greater and perhaps more than twice
as great on the 20-year horizon and is comparable when compared over 100 years.
Keywords Methane ·Greenhouse gases ·Global warming ·Natural gas ·Shale gas ·
Unconventional gas ·Fugitive emissions ·Lifecycle analysis ·LCA ·Bridge fuel ·
Transitional fuel ·Global warming potential ·GWP
Electronic supplementary material The online version of this article
(doi:10.1007/s10584-011-0061-5) contains supplementary material, which is available
to authorized users.
R. W. Howarth (B)·R. Santoro
Department of Ecology and Evolutionary Biology, Cornell University, Ithaca, NY 14853, USA
e-mail: rwh2@cornell.edu
A. Ingraffea
School of Civil and Environmental Engineering, Cornell University, Ithaca, NY 14853, USA
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Many view natural gas as a transitional fuel, allowing continued dependence on
fossil fuels yet reducing greenhouse gas (GHG) emissions compared to oil or coal
over coming decades (Pacala and Socolow 2004). Development of “unconventional”
gas dispersed in shale is part of this vision, as the potential resource may be large, and
in many regions conventional reserves are becoming depleted (Wood et al. 2011).
Domestic production in the U.S. was predominantly from conventional reservoirs
through the 1990s, but by 2009 U.S. unconventional production exceeded that of
conventional gas. The Department of Energy predicts that by 2035 total domestic
production will grow by 20%, with unconventional gas providing 75% of the total
(EIA 2010a). The greatest growth is predicted for shale gas, increasing from 16% of
total production in 2009 to an expected 45% in 2035.
Although natural gas is promoted as a bridge fuel over the coming few decades,
in part because of its presumed benefit for global warming compared to other fossil
fuels, very little is known about the GHG footprint of unconventional gas. Here, we
define the GHG footprint as the total GHG emissions from developing and using the
gas, expressed as equivalents of carbon dioxide, per unit of energy obtained during
combustion. The GHG footprint of shale gas has received little study or scrutiny,
although many have voiced concern. The National Research Council (2009) noted
emissions from shale-gas extraction may be greater than from conventional gas. The
Council of Scientific Society Presidents (2010) wrote to President Obama, warning
that some potential energy bridges such as shale gas have received insufficient analy-
sis and may aggravate rather than mitigate global warming. And in late 2010, the U.S.
Environmental Protection Agency issued a report concluding that fugitive emissions
of methane from unconventional gas may be far greater than for conventional gas
(EPA 2010).
Fugitive emissions of methane are of particular concern. Methane is the major
component of natural gas and a powerful greenhouse gas. As such, small leakages are
important. Recent modeling indicates methane has an even greater global warming
potential than previously believed, when the indirect effects of methane on at-
mospheric aerosols are considered (Shindell et al. 2009). The global methane budget
is poorly constrained, with multiple sources and sinks all having large uncertainties.
The radiocarbon content of atmospheric methane suggests fossil fuels may be a far
larger source of atmospheric methane than generally thought (Lassey et al. 2007).
The GHG footprint of shale gas consists of the direct emissions of CO2from end-
use consumption, indirect emissions of CO2from fossil fuels used to extract, develop,
and transport the gas, and methane fugitive emissions and venting. Despite the high
level of industrial activity involved in developing shale gas, the indirect emissions
of CO2are relatively small compared to those from the direct combustion of the
fuel: 1 to 1.5 g C MJ1(Santoro et al. 2011)vs15gCMJ
1for direct emissions
(Hayhoe et al. 2002). Indirect emissions from shale gas are estimated to be only
0.04 to 0.45 g C MJ1greater than those for conventional gas (Wood et al. 2011).
Thus, for both conventional and shale gas, the GHG footprint is dominated by the
direct CO2emissions and fugitive methane emissions. Here we present estimates for
methane emissions as contributors to the GHG footprint of shale gas compared to
conventional gas.
Our analysis uses the most recently available data, relying particularly on a
technical background document on GHG emissions from the oil and gas industry
(EPA 2010) and materials discussed in that report, and a report on natural gas
losses on federal lands from the General Accountability Office (GAO 2010). The
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EPA (2010) report is the first update on emission factors by the agency since
1996 (Harrison et al. 1996). The earlier report served as the basis for the national
GHG inventory for the past decade. However, that study was not based on random
sampling or a comprehensive assessment of actual industry practices, but rather only
analyzed facilities of companies that voluntarily participated (Kirchgessner et al.
1997). The new EPA (2010) report notes that the 1996 “study was conducted at
a time when methane emissions were not a significant concern in the discussion
about GHG emissions” and that emission factors from the 1996 report “are outdated
and potentially understated for some emissions sources.” Indeed, emission factors
presented in EPA (2010) are much higher, by orders of magnitude for some sources.
1 Fugitive methane emissions during well completion
Shale gas is extracted by high-volume hydraulic fracturing. Large volumes of water
are forced under pressure into the shale to fracture and re-fracture the rock to
boost gas flow. A significant amount of this water returns to the surface as flow-
back within the first few days to weeks after injection and is accompanied by large
quantities of methane (EPA 2010). The amount of methane is far more than could
be dissolved in the flow-back fluids, reflecting a mixture of fracture-return fluids
and methane gas. We have compiled data from 2 shale gas formations and 3 tight-
sand gas formations in the U.S. Between 0.6% and 3.2% of the life-time production
of gas from wells is emitted as methane during the flow-back period (Table 1).
We include tight-sand formations since flow-back emissions and the patterns of gas
production over time are similar to those for shale (EPA 2010). Note that the rate of
methane emitted during flow-back (column B in Table 1) correlates well to the initial
production rate for the well following completion (column C in Table 1). Although
the data are limited, the variation across the basins seems reasonable: the highest
methane emissions during flow-back were in the Haynesville, where initial pressures
and initial production were very high, and the lowest emissions were in the Uinta,
where the flow-back period was the shortest and initial production following well
completion was low. However, we note that the data used in Table 1are not well
documented, with many values based on PowerPoint slides from EPA-sponsored
workshops. For this paper, we therefore choose to represent gas losses from flow-
back fluids as the mean value from Table 1:1.6%.
More methane is emitted during “drill-out,” the stage in developing unconven-
tional gas in which the plugs set to separate fracturing stages are drilled out to release
gas for production. EPA (2007) estimates drill-out emissions at 142 ×103to 425 ×
103m3per well. Using the mean drill-out emissions estimate of 280 ×103m3(EPA
2007) and the mean life-time gas production for the 5 formations in Table 1(85 ×
106m3), we estimate that 0.33% of the total life-time production of wells is emitted as
methane during the drill-out stage. If we instead use the average life-time production
for a larger set of data on 12 formations (Wood et al. 2011), 45 ×106m3,weestimatea
percentage emission of 0.62%. More effort is needed to determine drill-out emissions
on individual formation. Meanwhile, in this paper we use the conservative estimate
of 0.33% for drill-out emissions.
Combining losses associated with flow-back fluids (1.6%) and drill out (0.33%),
we estimate that 1.9% of the total production of gas from an unconventional shale-gas
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Table 1 Methane emissions during the flow-back period following hydraulic fracturing, initial gas production rates following well completion, life-time gas
production of wells, and the methane emitted during flow-back expressed as a percentage of the life-time production for five unconventional wells in the United
(A) Methane emitted (B) Methane emitted per (C) Initial gas production (D) Life-time (E) Methane emitted
during flow-back day during flow-back at well completion production of during flow-back as %
(103m3)a(103m3day1)b(103m3day1)cwell (106m3)dof life-time productione
Haynesville (Louisiana, shale) 6,800 680 640 210 3.2
Barnett (Texas, shale) 370 41 37 35 1.1
Piceance (Colorado, tight sand) 710 79 57 55 1.3
Uinta (Utah, tight sand) 255 51 42 40 0.6
Den-Jules (Colorado, tight sand) 140 12 11 ? ?
Flow-back is the return of hydraulic fracturing fluids to the surface immediately after fracturing and before well completion. For these wells, the flow-back period
ranged from 5 to 12 days
aHaynesville: average from Eckhardt et al. (2009); Piceance: EPA (2007); Barnett: EPA (2004); Uinta: Samuels (2010); Denver-Julesburg: Bracken (2008)
bCalculated by dividing the total methane emitted during flow-back (column A) by the duration of flow-back. Flow-back durations were 9 days for Barnett(EPA
2004), 8 days for Piceance (EPA 2007), 5 days for Uinta (Samuels 2010), and 12 days for Denver-Julesburg (Bracken 2008); median value of 10 days for flow-back
was assumed for Haynesville
cHaynesville: http://shale.typepad.com/haynesvilleshale/2009/07/chesapeake-energy-haynesville-shale-decline-curve.html1/7/2011 and http://oilshalegas.com/
haynesvilleshalestocks.html; Barnett: http://oilshalegas.com/barnettshale.html; Piceance: Kruuskraa (2004) and Henke (2010); Uinta: http://www.epmag.com/
archives/newsComments/6242.htm; Denver-Julesburg: http://www.businesswire.com/news/home/20100924005169/en/Synergy-Resources-Corporation-Reports-
dBased on averages for these basins. Haynesville: http://shale.typepad.com/haynesvilleshale/decline-curve/); Barnett: http://www.aapg.org/explorer/2002/07jul/
barnett_shale.cfm and Wood et al. (2011); Piceance: Kruuskraa (2004); Uinta: http://www.epmag.com/archives/newsComments/6242.htm
eCalculated by dividing column (A) by column (D)
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Table 2 Fugitive methane emissions associated with development of natural gas from conventional
wells and from shale formations (expressed as the percentage of methane produced over the lifecycle
of a well)
Conventional gas Shale gas
Emissions during well completion 0.01% 1.9%
Routine venting and equipment leaks at well site 0.3 to 1.9% 0.3 to 1.9%
Emissions during liquid unloading 0 to 0.26% 0 to 0.26%
Emissions during gas processing 0 to 0.19% 0 to 0.19%
Emissions during transport, storage, and distribution 1.4 to 3.6% 1.4 to 3.6%
Total emissions 1.7 to 6.0% 3.6 to 7.9%
See text for derivation of estimates and supporting information
well is emitted as methane during well completion (Table 2). Again, this estimate is
uncertain but conservative.
Emissions are far lower for conventional natural gas wells during completion,
since conventional wells have no flow-back and no drill out. An average of 1.04 ×
103m3of methane is released per well completed for conventional gas (EPA 2010),
corresponding to 1.32 ×103m3natural gas (assuming 78.8% methane content of
the gas). In 2007, 19,819 conventional wells were completed in the US (EPA 2010),
so we estimate a total national emission of 26 ×106m3natural gas. The total
national production of onshore conventional gas in 2007 was 384 ×109m3(EIA
2010b). Therefore, we estimate the average fugitive emissions at well completion for
conventional gas as 0.01% of the life-time production of a well (Table 2), three orders
of magnitude less than for shale gas.
2 Routine venting and equipment leaks
After completion, some fugitive emissions continue at the well site over its lifetime.
A typical well has 55 to 150 connections to equipment such as heaters, meters, dehy-
drators, compressors, and vapor-recovery apparatus. Many of these potentially leak,
and many pressure relief valves are designed to purposefully vent gas. Emissions
from pneumatic pumps and dehydrators are a major part of the leakage (GAO 2010).
Once a well is completed and connected to a pipeline, the same technologies are used
for both conventional and shale gas; we assume that these post-completion fugitive
emissions are the same for shale and conventional gas. GAO (2010) concluded that
0.3% to 1.9% of the life-time production of a well is lost due to routine venting and
equipment leaks (Table 2). Previous studies have estimated routine well-site fugitive
emissions as approximately 0.5% or less (Hayhoe et al. 2002; Armendariz 2009)and
0.95% (Shires et al. 2009). Note that none of these estimates include accidents or
emergency vents. Data on emissions during emergencies are not available and have
never, as far as we can determine, been used in any estimate of emissions from
natural gas production. Thus, our estimate of 0.3% to 1.9% leakage is conservative.
As we discuss below, the 0.3% reflects use of best available technology.
Additional venting occurs during “liquid unloading.” Conventional wells fre-
quently require multiple liquid-unloading events as they mature to mitigate water
intrusion as reservoir pressure drops. Though not as common, some unconventional
wells may also require unloading. Empirical data from 4 gas basins indicate that 0.02
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to 0.26% of total life-time production of a well is vented as methane during liquid
unloading (GAO 2010). Since not all wells require unloading, we set the range at 0
to 0.26% (Table 2).
3 Processing losses
Some natural gas, whether conventional or from shale, is of sufficient quality to be
“pipeline ready” without further processing. Other gas contains sufficient amounts of
heavy hydrocarbons and impurities such as sulfur gases to require removal through
processing before the gas is piped. Note that the quality of gas can vary even within a
formation. For example, gas from the Marcellus shale in northeastern Pennsylvania
needs little or no processing, while gas from southwestern Pennsylvania must be
processed (NYDEC 2009). Some methane is emitted during this processing. The
default EPA facility-level fugitive emission factor for gas processing indicates a loss
of 0.19% of production (Shires et al. 2009). We therefore give a range of 0% (i.e. no
processing, for wells that produce “pipeline ready” gas) to 0.19% of gas produced as
our estimate of processing losses (Table 2). Actual measurements of processing plant
emissions in Canada showed fourfold greater leakage than standard emission factors
of the sort used by Shires et al. (2009) would indicate (Chambers 2004), so again, our
estimates are very conservative.
4 Transport, storage, and distribution losses
Further fugitive emissions occur during transport, storage, and distribution of natural
gas. Direct measurements of leakage from transmission are limited, but two studies
give similar leakage rates in both the U.S. (as part of the 1996 EPA emission factor
study; mean value of 0.53%; Harrison et al. 1996; Kirchgessner et al. 1997)andin
Russia (0.7% mean estimate, with a range of 0.4% to 1.6%; Lelieveld et al. 2005).
Direct estimates of distribution losses are even more limited, but the 1996 EPA
study estimates losses at 0.35% of production (Harrison et al. 1996; Kirchgessner
et al. 1997). Lelieveld et al. (2005) used the 1996 emission factors for natural gas
storage and distribution together with their transmission estimates to suggest an
overall average loss rate of 1.4% (range of 1.0% to 2.5%). We use this 1.4% leakage
as the likely lower limit (Table 2). As noted above, the EPA 1996 emission estimates
are based on limited data, and Revkin and Krauss (2009) reported “government
scientists and industry officials caution that the real figure is almost certainly higher.”
Furthermore, the IPCC (2007) cautions that these “bottom-up” approaches for
methane inventories often underestimate fluxes.
Another way to estimate pipeline leakage is to examine “lost and unaccounted for
gas,” e.g. the difference between the measured volume of gas at the wellhead and that
actually purchased and used by consumers. At the global scale, this method has esti-
mated pipeline leakage at 2.5% to 10% (Crutzen 1987; Cicerone and Oremland 1988;
Hayhoe et al. 2002), although the higher value reflects poorly maintained pipelines in
Russia during the Soviet collapse, and leakages in Russia are now far less (Lelieveld
et al. 2005; Reshetnikov et al. 2000). Kirchgessner et al. (1997) argue against this
approach, stating it is “subject to numerous errors including gas theft, variations in
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temperature and pressure, billing cycle differences, and meter inaccuracies.” With
the exception of theft, however, errors should be randomly distributed and should
not bias the leakage estimate high or low. Few recent data on lost and unaccounted
gas are publicly available, but statewide data for Texas averaged 2.3% in 2000 and
4.9% in 2007 (Percival 2010). In 2007, the State of Texas passed new legislation to
regulate lost and unaccounted for gas; the legislation originally proposed a 5% hard
cap which was dropped in the face of industry opposition (Liu 2008; Percival 2010).
We take the mean of the 2000 and 2007 Texas data for missing and unaccounted gas
(3.6%) as the upper limit of downstream losses (Table 2), assuming that the higher
value for 2007 and lower value for 2000 may potentially reflect random variation in
billing cycle differences. We believe this is a conservative upper limit, particularly
given the industry resistance to a 5% hard cap.
Our conservative estimate of 1.4% to 3.6% leakage of gas during transmission,
storage, and distribution is remarkably similar to the 2.5% “best estimate” used by
Hayhoe et al. (2002). They considered the possible range as 0.2% and 10%.
5 Contribution of methane emissions to the GHG footprints
of shale gas and conventional gas
Summing all estimated losses, we calculate that during the life cycle of an average
shale-gas well, 3.6 to 7.9% of the total production of the well is emitted to the
atmosphere as methane (Table 2). This is at least 30% more and perhaps more
than twice as great as the life-cycle methane emissions we estimate for conventional
gas, 1.7% to 6%. Methane is a far more potent GHG than is CO2, but methane
also has a tenfold shorter residence time in the atmosphere, so its effect on global
warming attenuates more rapidly (IPCC 2007). Consequently, to compare the global
warming potential of methane and CO2requires a specific time horizon. We follow
Lelieveld et al. (2005) and present analyses for both 20-year and 100-year time
horizons. Though the 100-year horizon is commonly used, we agree with Nisbet et al.
(2000) that the 20-year horizon is critical, given the need to reduce global warming
in coming decades (IPCC 2007). We use recently modeled values for the global
warming potential of methane compared to CO2: 105 and 33 on a mass-to-mass basis
for 20 and 100 years, respectively, with an uncertainty of plus or minus 23% (Shindell
et al. 2009). These are somewhat higher than those presented in the 4th assessment
report of the IPCC (2007), but better account for the interaction of methane with
aerosols. Note that carbon-trading markets use a lower global-warming potential
yet of only 21 on the 100-year horizon, but this is based on the 2nd IPCC (1995)
assessment, which is clearly out of date on this topic. See Electronic Supplemental
Materials for the methodology for calculating the effect of methane on GHG in terms
of CO2equivalents.
Methane dominates the GHG footprint for shale gas on the 20-year time horizon,
contributing 1.4- to 3-times more than does direct CO2emission (Fig. 1a). At this
time scale, the GHG footprint for shale gas is 22% to 43% greater than that for
conventional gas. When viewed at a time 100 years after the emissions, methane
emissions still contribute significantly to the GHG footprints, but the effect is
diminished by the relatively short residence time of methane in the atmosphere. On
this time frame, the GHG footprint for shale gas is 14% to 19% greater than that for
conventional gas (Fig. 1b).
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Fig. 1 Comparison of greenhouse gas emissions from shale gas with low and high estimates of
fugitive methane emissions, conventional natural gas with low and high estimates of fugitive methane
emissions, surface-mined coal, deep-mined coal, and diesel oil. ais for a 20-year time horizon, and
bis for a 100-year time horizon. Estimates include direct emissions of CO2during combustion (blue
bars), indirect emissions of CO2necessary to develop and use the energy source (red bars), and
fugitive emissions of methane, converted to equivalent value of CO2as described in the text (pink
bars). Emissions are normalized to the quantity of energy released at the time of combustion. The
conversion of methane to CO2equivalents is based on global warming potentials from Shindell et al.
(2009) that include both direct and indirect influences of methane on aerosols. Mean values from
Shindell et al. (2009) are used here. Shindell et al. (2009) present an uncertainty in these mean values
of plus or minus 23%, which is not included in this figure
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6 Shale gas versus other fossil fuels
Considering the 20-year horizon, the GHG footprint for shale gas is at least 20%
greater than and perhaps more than twice as great as that for coal when expressed per
quantity of energy available during combustion (Fig. 1a; see Electronic Supplemental
Materials for derivation of the estimates for diesel oil and coal). Over the 100-year
frame, the GHG footprint is comparable to that for coal: the low-end shale-gas
emissions are 18% lower than deep-mined coal, and the high-end shale-gas emissions
are 15% greater than surface-mined coal emissions (Fig. 1b). For the 20 year horizon,
the GHG footprint of shale gas is at least 50% greater than for oil, and perhaps 2.5-
times greater. At the 100-year time scale, the footprint for shale gas is similar to or
35% greater than for oil.
We know of no other estimates for the GHG footprint of shale gas in the peer-
reviewed literature. However, we can compare our estimates for conventional gas
with three previous peer-reviewed studies on the GHG emissions of conventional
natural gas and coal: Hayhoe et al. (2002), Lelieveld et al. (2005), and Jamarillo et al.
(2007). All concluded that GHG emissions for conventional gas are less than for
coal, when considering the contribution of methane over 100 years. In contrast, our
analysis indicates that conventional gas has little or no advantage over coal even
over the 100-year time period (Fig. 1b). Our estimates for conventional-gas methane
emissions are in the range of those in Hayhoe et al. (2002) but are higher than those
in Lelieveld et al. (2005) and Jamarillo et al. (2007) who used 1996 EPA emission
factors now known to be too low (EPA 2010). To evaluate the effect of methane, all
three of these studies also used global warming potentials now believed to be too low
(Shindell et al. 2009). Still, Hayhoe et al. (2002) concluded that under many of the
scenarios evaluated, a switch from coal to conventional natural gas could aggravate
global warming on time scales of up to several decades. Even with the lower global
warming potential value, Lelieveld et al. (2005) concluded that natural gas has a
greater GHG footprint than oil if methane emissions exceeded 3.1% and worse than
coal if the emissions exceeded 5.6% on the 20-year time scale. They used a methane
global warming potential value for methane from IPCC (1995) that is only 57% of
the new value from Shindell et al. (2009), suggesting that in fact methane emissions
of only 2% to 3% make the GHG footprint of conventional gas worse than oil and
coal. Our estimates for fugitive shale-gas emissions are 3.6 to 7.9%.
Our analysis does not consider the efficiency of final use. If fuels are used to
generate electricity, natural gas gains some advantage over coal because of greater
efficiencies of generation (see Electronic Supplemental Materials). However, this
does not greatly affect our overall conclusion: the GHG footprint of shale gas ap-
proaches or exceeds coal even when used to generate electricity (Table in Electronic
Supplemental Materials). Further, shale-gas is promoted for other uses, including as
a heating and transportation fuel, where there is little evidence that efficiencies are
superior to diesel oil.
7 Can methane emissions be reduced?
The EPA estimates that ’green’ technologies can reduce gas-industry methane emis-
sions by 40% (GAO 2010). For instance, liquid-unloading emissions can be greatly
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reduced with plunger lifts (EPA 2006;GAO2010); industry reports a 99% venting
reduction in the San Juan basin with the use of smart-automated plunger lifts (GAO
2010). Use of flash-tank separators or vapor recovery units can reduce dehydrator
emissions by 90% (Fernandez et al. 2005). Note, however, that our lower range of
estimates for 3 out of the 5 sources as shown in Table 2already reflect the use of
best technology: 0.3% lower-end estimate for routine venting and leaks at well sites
(GAO 2010), 0% lower-end estimate for emissions during liquid unloading, and 0%
during processing.
Methane emissions during the flow-back period in theory can be reduced by up to
90% through Reduced Emission Completions technologies, or REC (EPA 2010).
However, REC technologies require that pipelines to the well are in place prior
to completion, which is not always possible in emerging development areas. In any
event, these technologies are currently not in wide use (EPA 2010).
If emissions during transmission, storage, and distribution are at the high end of
our estimate (3.6%; Table 2), these could probably be reduced through use of better
storage tanks and compressors and through improved monitoring for leaks. Industry
has shown little interest in making the investments needed to reduce these emission
sources, however (Percival 2010).
Better regulation can help push industry towards reduced emissions. In reconcil-
ing a wide range of emissions, the GAO (2010) noted that lower emissions in the
Piceance basin in Colorado relative to the Uinta basin in Utah are largely due to a
higher use of low-bleed pneumatics in the former due to stricter state regulations.
8 Conclusions and implications
The GHG footprint of shale gas is significantly larger than that from conventional
gas, due to methane emissions with flow-back fluids and from drill out of wells
during well completion. Routine production and downstream methane emissions are
also large, but are the same for conventional and shale gas. Our estimates for these
routine and downstream methane emission sources are within the range of those
reported by most other peer-reviewed publications inventories (Hayhoe et al. 2002;
Lelieveld et al. 2005). Despite this broad agreement, the uncertainty in the magnitude
of fugitive emissions is large. Given the importance of methane in global warming,
these emissions deserve far greater study than has occurred in the past. We urge
both more direct measurements and refined accounting to better quantify lost and
unaccounted for gas.
The large GHG footprint of shale gas undercuts the logic of its use as a bridging
fuel over coming decades, if the goal is to reduce global warming. We do not intend
that our study be used to justify the continued use of either oil or coal, but rather to
demonstrate that substituting shale gas for these other fossil fuels may not have the
desired effect of mitigating climate warming.
Finally, we note that carbon-trading markets at present under-value the green-
house warming consequences of methane, by focusing on a 100-year time horizon
and by using out-of-date global warming potentials for methane. This should be
corrected, and the full GHG footprint of unconventional gas should be used in
planning for alternative energy futures that adequately consider global climate
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Acknowledgements Preparation of this paper was supported by a grant from the Park Foundation
and by an endowment funds of the David R. Atkinson Professorship in Ecology & Environmental
Biology at Cornell University. We thank R. Alvarez, C. Arnold, P. Artaxo, A. Chambers, D.
Farnham, P. Jamarillo, N. Mahowald, R. Marino, R. McCoy, J. Northrup, S. Porder, M. Robertson,
B. Sell, D. Shrag, L. Spaeth, and D. Strahan for information, encouragement, advice, and feedback
on our analysis and manuscript. We thank M. Hayn for assistance with the figures. Two anonymous
reviewers and Michael Oppenheimer provided very useful comments on an earlier version of this
Open Access This article is distributed under the terms of the Creative Commons Attribution
Noncommercial License which permits any noncommercial use, distribution, and reproduction in
any medium, provided the original author(s) and source are credited.
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... No obstante este alto potencial, se han reportado impactos ambientales importantes debido a la explotación del gas de lutitas en Estados Unidos. Entre estos impactos encontramos las emisiones de gases de efecto invernadero debido a las fugas de gas en los procesos de extracción, procesamiento y transporte (Howarth y Santoro, 2011); un gran uso de agua, ya que para la perforación de un pozo se pueden requerir hasta 14.7 millones de litros (De la Vega-Navarro y Ramírez-Villegas, 2015); posibilidades de contaminación de mantos acuíferos con agua contaminada por el proceso de extracción; impactos a la salud por los químicos que son inyectados a los pozos, ya que al menos algunas de las substancias ...
Carbon neutrality has been proposed as a solution for the current severe energy and climate crisis caused by the overuse of fossil fuels, and machine learning (ML) has exhibited excellent performance in accelerating related research owing to its powerful capacity for big data processing. This review presents a detailed overview of ML accelerated carbon neutrality research with a focus on energy management, screening of novel energy materials, and ML interatomic potentials (MLIPs), with illustrations of two selected MLIP algorithms: moment tensor potential (MTP) and neural equivariant interatomic potential (NequIP). We conclude by outlining the important role of ML in accelerating the achievement of carbon neutrality from global-scale energy management, unprecedented screening of advanced energy materials in massive chemical space, to the revolution of atomic-scale simulations of MLIPs, which has the bright prospect of applications.
Hydrogen can be blended with other surrogate fuels to avoid its hazard as a highly flammable and explosive gas. The effect of hydrogen addition on the ignition delay times of n-pentane, 3-pentanone, and 1-pentene was investigated by measuring the ignition delay times in a rapid compression machine. The experiments were performed at pressures of 10, 15, and 20 bar, equivalence ratios 0.5 and 1 and for temperatures ranging from 650 to 970 K. The molar ratios of hydrogen in the fuel mixtures were 0, 25 and 50%. The experimental data were simulated using recent models from literature, yielding good agreement. The overall observations conclude to a minor effect of hydrogen addition in the case of n-pentane and 3-pentanone, resulting in a decrease of the reactivity when the mole fraction of hydrogen increases. Hydrogen does however not impact the ignition delay times of 1-pentene significantly. Kinetic analysis is performed to shed light into the processes responsible for this phenomenon.
Climate change is the most important issue now facing humanity. As global temperatures increase, floods, fires and storms are becoming both more intense and frequent. People are suffering. And yet, emissions continue to rise. This book unpacks the activities of the key actors which have organised past and present climate responses – specifically, corporations, governments, and civil society organisations. Analysing three elements of climate change – mitigation, adaptation and suffering – the authors show how exponential growth of the capitalist system has allowed the fossil fuel industry to maintain its dominance. However, this hegemonic position is now coming under threat as new and innovative social movements have emerged, including the fossil fuel divestment movement, Fridays for Future, Extinction Rebellion and others. In exposing the inadequacies of current climate policies and pointing to the possibilities of new social and economic systems, this book highlights how the worst impacts of climate change can be avoided.
The growth of natural gas production in the United States has been boosted by shale-gas production in the Appalachian Basin in the Northeast, the Permian Basin in western Texas and New Mexico, and the Haynesville Shale in Texas and Louisiana. Shale gas is an unconventional gas resource. It differs from the conventional gas resource, which produces natural gas from granular, porous, and permeable formations. The term “shale gas” refers to thermogenic or biogenic gas produced from organic-rich, fine-grained, low-permeability sedimentary rocks (e.g., shale, mudstone, mudrock, and associated lithofacies) upon extensive fracturing. The unconventional shale gas resource is a self-contained system where the rock functions as the hydrocarbon source, migration pathway, reservoir, and seal. Additionally, the shale gas resource requires enhanced drilling/production technologies (e.g., hydraulic fracturing) in order to be produced at economic rates. The gas occurs as free and adsorbed states in the pore spaces. Much gas is adsorbed on the surface of minerals (especially clay minerals) and OM. Therefore the approach to the study of the geological characteristics of a shale gas play is distinctive. To accurately predict the shale gas resource potential, there must be a thorough assessment of the paleodepositional environment, organic geochemistry, thermal maturity, reservoir thickness, mineralogy, mechanical property, porosity, and permeability.
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Portable or even on-chip detection of methane (CH 4 ) is significant for environmental protection and production safety. However, optical sensing systems are usually based on discrete optical elements, which makes them unsuitable for the occasions with high portability requirement. In this work, we report on-chip silicon-on-insulator (SOI) waveguide CH 4 sensors at 3.291 μm based on two measurement schemes including direct absorption spectroscopy (DAS) and wavelength modulation spectroscopy (WMS). In order to suppress noise, Kalman filter was adopted in signal processing. By optimizing the waveguide cross-section structure, an etch depth of 220 nm was selected with an experimentally high power confinement factor (PCF) of 23% and a low loss of only 0.71 dB/cm. A limit of detection (LoD) of 155 parts-per-million (ppm) by DAS and 78 ppm by WMS at an averaging time of 0.2 s were obtained for a 2 cm-long waveguide sensor. Compared to the chalcogenide (ChG) waveguide CH 4 sensors at the same wavelength, the reported sensor reveals the minimum waveguide loss and the lowest LoD. Therefore the SOI waveguide sensor has the potential of on-chip gas sensing in the mid-infrared (MIR) waveband.
The environmental implications of unconventional oil and gas extraction are only recently starting to be systematically recorded. Our research shows the utility of microbial communities paired with geochemical markers to build strong predictive random forest models of unconventional oil and gas activity and the identification of key biomarkers.
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Methane is the most abundant organic chemical in Earth's atmosphere, and its concentration is increasing with time. Photochemical reactions oxidize methane in the atmosphere; through these reactions, methane exerts strong influence over the chemistry of the troposphere and the stratosphere and many species including ozone, hydroxyl radicals, and carbon monoxide. Also, through its infrared absorption spectrum, methane is an important greenhouse gas in the climate system. The key roles and reactions of methane are described and enumerated. Two kinds of methane production are examined in detail: microbial and thermogenic. Microbial methanogenesis is described, and key organisms and substrates are identified along with their properties and habitats. Microbial methane oxidation limits the release of methane from certain methanogenic areas. Both aerobic and anaerobic oxidation are described along with methods to measure rates of methane production and oxidation experimentally. Indicators of the origin of methane, including C and H isotopes, are reviewed. Several constraints on the budget of atmospheric methane, its sources, sinks and residence time are identified and evaluated. From these constraints and other data on sources and inks, a list of sources and sinks, identities, and sizes are constructed. 299 refs., 11 figs., 4 tabs.
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Substitution of natural gas for coal is one means of reducing carbon dioxide (CO2) emissions. However, natural gas and coal use also results in emissions of other radiatively active substances including methane (CH4), sulfur dioxide (SO2), a sulfate aerosolprecursor, and black carbon (BC) particles. Will switching from coal to gas reduce the net impact of fossil fuel use on global climate? Using the electric utility sector as an example, changes in emissions of CO2, CH4,SO2 and BC resulting from the replacement of coal by natural gas are evaluated, and their modeled net effect on global mean-annual temperature calculated. Coal-to-gas substitution initially produces higher temperatures relative to continued coal use. This warming is due to reduced SO2 emissionsand possible increases in CH4 emissions, and can last from 1 to 30years, depending on the sulfur controls assumed. This is followed by a net decrease in temperature relative to continued coal use, resulting from lower emissions of CO2 and BC. The length of this period and the extent of the warming or cooling expected from coal-to-gas substitution is found to depend on key uncertainties and characteristics of the substitutions, especially those related to: (1) SO2 emissions and consequentsulphate aerosol forcing; and (2) the relative efficiencies of the power plantsinvolved in the switch.
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Evaluating multicomponent climate change mitigation strategies requires knowledge of the diverse direct and indirect effects of emissions. Methane, ozone, and aerosols are linked through atmospheric chemistry so that emissions of a single pollutant can affect several species. We calculated atmospheric composition changes, historical radiative forcing, and forcing per unit of emission due to aerosol and tropospheric ozone precursor emissions in a coupled composition-climate model. We found that gas-aerosol interactions substantially alter the relative importance of the various emissions. In particular, methane emissions have a larger impact than that used in current carbon-trading schemes or in the Kyoto Protocol. Thus, assessments of multigas mitigation policies, as well as any separate efforts to mitigate warming from short-lived pollutants, should include gas-aerosol interactions.
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The cycling of <sup>14</sup>CH<sub>4</sub> (''radiomethane'') through the atmosphere has been strongly perturbed in the industrial era by the release of <sup>14</sup>C-free methane from geologic reservoirs (''fossil methane'' emissions), and in the nuclear era, especially since ca 1970, by the direct release of nucleogenic radiomethane from nuclear power facilities. Contemporary measurements of atmospheric radiomethane have been used to estimate the proportion of fossil methane in the global methane source (the ''fossil fraction''), but such estimates carry high uncertainty due to the ill-determined nuclear-power source. We exploit an analysis in a companion paper of the global radiomethane budget through the nuclear era, using contemporary measurements of atmospheric radiomethane since 1986 to quantify both the fossil fraction and the strength of the nuclear power source. We deduce that 28.6±1.9% (1 s.d.) of the global methane source has fossil origin, a fraction which may include some <sup>14</sup>C-depleted refractory carbon fraction such as in aged peat deposits. The co-estimated strength of the global nuclear-power source of radiomethane is consistent with values inferred independently from local nuclear facilities.
1 1.0 EXECUTIVE SUMMARY Natural gas production in the Barnett Shale region of Texas has increased rapidly since 1999, and as of June 2008, over 7700 oil and gas wells had been installed and another 4700 wells were pending. Gas production in 2007 was approximately 923 Bcf from wells in 21 counties. Natural gas is a critical feedstock to many chemical production processes, and it has many environmental benefits over coal as a fuel for electricity generation, including lower emissions of sulfur, metal compounds, and carbon dioxide. Nevertheless, oil and gas production from the Barnett Shale area can impact local air quality and release greenhouse gases into the atmosphere. The objectives of this study were to develop an emissions inventory of air pollutants from oil and gas production in the Barnett Shale area, and to identify cost-effective emissions control options. Emission sources from the oil and gas sector in the Barnett Shale area were divided into point sources, which included compressor engine exhausts and oil/condensate tanks, as well as fugitive and intermittent sources, which included production equipment fugitives, well drilling and fracing engines, well completions, gas processing, and transmission fugitives. The air pollutants considered in this inventory were smog-forming compounds (NO x and VOC), greenhouse gases, and air toxic chemicals. For 2009, emissions of smog-forming compounds from compressor engine exhausts and tanks were predicted to be approximately 96 tons per day (tpd) on an annual average, with peak summer emissions of 212 tpd. Emissions during the summer increase because of the effects of temperature on volatile organic compound emissions from storage tanks. Emissions of smog-forming compounds in 2009 from all oil and gas sources were estimated to be approximately 191 tpd on an annual average, with peak summer emissions of 307 tpd. The portion of those emissions originating from the 5-counties in the D-FW metropolitan area with significant oil and gas production was 165 tpd during the summer.
To the naked eye, there was nothing to be seen at a natural gas well in eastern Texas but beige pipes and tanks baking in the sun. But in the viewfinder of Terry Gosney's infrared camera, three black plumes of gas gushed through leaks that were otherwise invisible. "Holy smoke, it's blowing like mad," said Mr. Gosney, an environmental field coordinator for EnCana, the Canadian gas producer that operates the year-old well near Franklin, Tex. "It does look nasty." Within a few days the leaks had been sealed by workers. Efforts like EnCana's save energy and money. Yet they are also a cheap, effective way of blunting climate change that could potentially be replicated thousands of times over, from Wyoming to Siberia, energy experts say. Natural gas consists almost entirely of methane, a potent heat-trapping gas that scientists say accounts for as much as a third of the human contribution to global warming. "This for me is an absolute no-brainer, even more so than putting in those compact fluorescent bulbs in your house," said Al Armendariz, an engineer at Southern Methodist University who studies pollutants from oil and gas fields.
The report describes the results of a study to quantify the annual methane emissions from the natural gas industry.
An inventory of natural gas losses from the former Soviet Union's gas industry has been constructed from published Russian-language sources. The results imply that in the late 1980s/early 1990s annual losses from Russia were in the range 35-59×109 cubic meters (24-40 Tg of CH4): estimates based on what are thought to be the more reliable sources place annual losses in the range 37-52×109 cubic meters (25-35 Tg of CH4). Of this amount, one half to two thirds of the emissions may have been from the extremely long and ageing gas pipeline system. Extrapolation of the estimates for Russian losses to the whole territory of the former Soviet Union suggests a probable total annual emission level from the whole ex-Soviet gas industry in the range 47-67×109 cubic meters of natural gas or 31-45 Tg of CH4 in these years. The envelope of minimum and maximum estimates for emissions from the former Soviet Union ranges from 29 to 50 Tg of methane. The limited availability of systematic and accurate published information on the emissions introduces significant uncertainty into the estimate. In an attempt to constrain emissions better, estimates of losses from specific causes were made using two or more independent approaches, where possible. A reasonable agreement between estimates was achieved in those cases. Our results imply that substantial reductions in emissions could be achieved by investment to reduce losses. Because of the high global warming potential and short lifetime of methane compared to carbon dioxide, reducing the large losses from the FSU may be among the most cost-effective short-term approaches available to reduce global anthropogenic greenhouse warming.