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F
Atmospheric Emissions from Fossil Fuel
and Nuclear Electricity Generation
GREENHOUSE GAS EMISSIONS
Coal
Because of its high C-to-H ratio, coal is potentially the highest emitter of the
energy sources available when it comes to greenhouse gas emissions. Emissions for
traditional pulverized coal (pc) plants hover near or above 1,000 g CO2e/kWh, about 2
orders of magnitude larger than most estimates for renewables. However the emissions
can be significantly mitigated to as low as ~40 g CO2e/kWh with different configurations
and most notably with carbon capture and storage (CCS) technologies, assuming that
CCS can be successfully implemented (See Figure E-1).
Estimates for CO2 emissions from pulverized coal plants currently deployed range
from 960 and 1,050 g CO2e/kWh; these estimates include the average for the United
States, the United Kingdom, and Japan, as well as the average for the United States
operating under new source performance standards (NSPS). Modest reductions (757 to
879 g CO2e/kWh) are projected for new technologies that increase plant efficiency; these
include a future low emission boiler system (LEBS) (Spath et al., 1999), a U.K.
supercritical pulverized coal plant (Odeh and Cockerill, 2008), and a U.K. integrated
gasification combined cycle (IGCC) plant (Odeh and Cockerill, 2008). Emissions from a
coal co-fired with biomass waste residue facility are estimated at 681 g CO2e/kWh (Spath
and Mann, 2004).
The lower end of the range from 43 to 255 g CO2e/kWh includes a variety of coal
technologies with future CCS methods. The carbon capture methods discussed in the
literature include absorption by monoethanolamine (MEA) and selexol. (MEA is a post
combustion CO2 capture method for the traditional pulverized coal and biomass co-fired
plants and thus could be used with the existing fleet. Selexol is used to capture CO2 prior
to combustion in IGCC plants.) A hypothetical U.K. IGCC plant with carbon capture via
selexol had a value of 167 g CO2e/kWh (Odeh and Cockerill, 2008). Two hypothetical
U.S. and U.K. average coal plants with carbon capture via MEA emit approximately
250 g CO2e/kWh (Odeh and Cockerill, 2008; Spath and Mann, 2004). The lowest value
of 43 g CO2e/kWh is from a hypothetical coal plant co-fired with biomass residues
(Spath and Mann, 2004). However, this estimate did not account for CO2 emissions
associated with the production, regeneration or disposal of MEA.
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Because MEA is highly reactive with SO2, Odeh and Cockerill (2008) also
evaluated a pulverized coal plant with CCS, but without flue gas desulfurization (FGD) to
evaluate how the life-cycle emissions of CO2 would be affected by the interaction of the
MEA with SO2. Under this scenario significantly more MEA would be required and
because of the extra emissions associated with producing MEA and other materials used
in the capture process, they found that life-cycle CO2e emissions doubled.
Natural Gas
Key factors affecting natural gas CO2 emissions from natural gas facilities include
plant efficiency and natural gas losses from production and distribution. Emissions for
natural gas combined cycle (NGCC) plants had a small range of 469 to 518 g CO2e/kWh.
A higher value of 608 g CO2e/kWh was reported for the only gas-fired plant evaluated
(Hondo, 2005). CCS is not expected to have as large an impact on natural gas carbon
emissions as it does for coal because upstream emissions are more significant in the
natural gas fuel cycle. Two studies evaluated the future deployment of CCS with MEA
for NGCC plants. Odeh and Cockerill (2008) found CCS reduced emissions from 488 to
200 g CO2e/kWh and Spath and Mann (2004) found emissions dropped from 499 to
245 g CO2e/kWh. The Spath and Mann (2004) result does not include CO2 emissions
associated with production, regeneration or disposal of MEA.
Nuclear
For nuclear technologies, the studies reviewed report values from 3 to 106 g
CO2e/kWh, with all values except the low and high values clustered from 15 to 25 g
CO2e/kWh. The low value of 3 g CO2e/kWh is from Vattenfall (2004) and the high value
of 108 g CO2e/kWh is from Storm van Leeuwen and Smith (2008). The Vattenfall study
used PA methods to analyze two Swedish reactors where 80% of the fuel enrichment was
performed by centrifuge. The reactors were assumed to operate at 85% capacity with a
life expectancy of 40 years. The Storm van Leeuwen and Smith (2008) study used EIO
methods to analyze a nuclear facility located outside of Sweden with fuel enrichment via
gas diffusion and an 82% operational capacity over a life expectancy of 30 years. The
nuclear subgroup of the AEF committee uses a narrower range of 24 to 55 g CO2e/kWh.
The narrower range was developed by the nuclear subgroup of the AEF committee to
represent the CO2 emissions from the current fuel enrichment situation in the United
States.
Fthenakis and Kim (2007) attribute most of the difference between low and high
estimates on nuclear power to three factors: the energy mix of the country developing the
plant, whether enrichment is via centrifuge or diffusion (diffusion tends to use 40% more
electricity), and the type of LCA method used. They found that EIO methods gave
estimates 10-20 times higher than PA methods for side by side comparisons of nuclear
plant construction. The difference between the results of these studies is a topic of
interest in the nuclear power industry.
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SO2 EMISSIONS
Coal
Because of coal’s high sulfur content, traditional pc plants have the highest SO2
emissions of all technologies considered here—approaching 7,000 mg k/Wh of SO2.
Significantly lower emissions, however, are estimated for different coal-based
configurations. The high-end values correspond to two cases from the United States: one
case with 6,700 mg SO2/kWh based on average U.S. coal plant emissions in 1995 and a
plant that complied with the New Source Performance Standard (NSPS) with 2,530 mg
SO2/kWh (Spath et al., 1999). The mid-range includes several cases from the United
Kingdom that have SO2 values of 1,000 to 1,250 mg/kWh (Berry et al., 1998; Odeh and
Cockerill, 2008). Spath et al. (1999) analyzed a coal-fired plant with a low-emission
boiler system (LEBS) that emitted 720 mg SO2/kWh.
IGCC plants with or without CCS are estimated to emit between 200 mg and 330
mg SO2/kWh. Odeh and Cockerill (2008) found that CCS to an IGCC plant caused a 10%
increase SO2 emissions. On the other hand, the lowest SO2 emissions were estimated for
a supercritical coal plant with carbon capture via MEA. In this case SO2 emissions were
reduced from 1,250 to 9 mg/kWh (Odeh and Cockerill, 2008), primarily by increasing
SO2 removal efficiency from 90% to 98% with flue gas desulfurization (FGD).
Natural Gas
Natural gas SO2 emission data was reviewed for three studies that reported
negligible to 324 mg SO2/kWh. Different methodological assumptions contribute to the
very divergent results from the European and U.S. studies. The U.K. ExternE (Berry et
al., 1998) study assumed SO2 negligible through the fuel cycle and the German ExternE
study (European Commission, 1997) had a very small value of 3 mg SO2/kWh from
extraction only. In contrast, the U.S. study assigned a large value of 324 mg/kWh for SO2
emissions with over 80% of the emissions from gas production and distribution and about
15% from construction and decommissioning of plant (Spath and Mann, 2000).
NOx EMISSIONS
Coal
As is the case for other gaseous emissions, coal has potentially the greatest rate of
NOx emissions. Estimates range from 100 to 3,350 mg/kWh. These values represent a
number of different configurations including current average practices, future practices,
different power plant designs, and with CCS technologies. The high end of the range
includes a U.S. NSPS, an average U.S., and an average U.K. case. The average U.S. case
emitted 3,350 mg NOx/kWh (Spath et al., 1999), the U.S. NSPS case emitted 2,340 mg
NOx/kWh (Spath et al., 1999), and the average U.K. case emitted 2,200 mg NOx/kWh
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(Berry et al., 1998). Hypothetical future cases from Berry et al. (1998) and Spath et al.
(1999) had mid-range values of 540 to 1,000 mg NOx/kWh. Emission results from Odeh
and Cockerill (2008) suggest pulverized coal plants with CCS via MEA will experience
an increase in NOx emissions. They found that carbon capture via MEA increased air
emissions of NOx from 410 to 590 mg/kWh for a supercritical pulverized coal plant with
SCR, FGD, and ESP. (NH3 increases from 5 to 470 mg/kWh with CCS via MEA for coal
because oxidation of MEA produces ammonia.)
The lowest NOx emission values were from an IGCC. Without CCS NOx
emissions were estimated at 120 mg/kWh; with CCS via selexol, NOx emissions were
estimated to decrease by 17% to 100 mg/kWh.
Natural Gas
NOx emissions for NGCC plants were estimated to considerable, ranging from
140 to 570 mg/kWh. The high value is from Spath and Mann (2000) for an average U.S.
plant with SCR. The U.K. case with low NOx burners had a value of 460 mg/kWh (Berry
et al., 1998). The ExternE case in Germany reported a value of 277 mg/kWh for a plant
with no NOx controls (European Commission, 1997).
The lowest estimated emissions (140 mg/kWh) were from a study by Odeh and
Cockerill (2008) of a plant equipped with SCR. They found that the addition of CCR
using MEA increased NOx emissions by 14% to 60 mg/kWh.
PARTICULATE MATTER EMISSIONS
Coal
Coal has a very wide range of PM emission values. At the low end (4 mg/kWh)
the estimated emission rate is as low as or lower than renewables. The high end
estimates, approaching 10,000 mg/kWh are an order of magnitude or larger than all other
technologies. An emission rate of 9,210 mg PM/kWh was estimated for an average U.S.
coal-fired plant, while a U.S. NSPS plant was estimated to emit 9,780 mg/kWh (Spath et
al., 1999). Future cases range from 4 to 160 mg/kWh and represent a variety of pollution
controls and burner types. At the low end, a hypothetical IGCC plant configured with
SO2, NOx, and PM removal systems emitted 4 mg/kWh (Odeh and Cockerill, 2008).
CCS had no impact on the estimated PM emissions.
Natural Gas
Two LCA studies for PM emissions from natural gas facilities were found. They
reported very different results. The U.S. study estimated a large emission rate of 133 mg
PM/kWh (Spath and Mann, 2000), whereas an ExternE study in Germany estimated a
rate of 18 mg PM/kWh (European Commission, 1997). The difference in the PM
emission results is due in part to differing methodological assumptions. In the U.S. study,
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Spath and Mann (2000) found that approximately equal percentages of PM were emitted
from upstream processes and from the power plant itself, while the German ExternE
study found negligible PM emissions from power generation (European Commission,
1997).
REFERENCES
Berry, J.E., M.R. Holland, P.R. Watkiss, R. Boyd, and W. Stephenson. 1998. Power
Generation and the Environment—A U.K. Perspective. European Commission,
June 1998.
Denholm, P.L. 2004, Environmental and Policy Analysis of Renewable Energy Enabling
Technologies, Ph.D. dissertation, University of Wisconsin, Madison.
European Commission. 1997. ExternE National Implementation Germany. Available at
http://externe.jrc.es/reports.html.
Fthenakis, V.M., and H.C. Kim. 2007, Greenhouse-gas emissions from solar electric- and
nuclear power: A life-cycle study. Energy Policy 35:2549-2557.
Hondo, H. 2005. Life cycle GHG emission analysis of power generation systems:
Japanese case, Energy 30:2042–2056.
Odeh, N.A., and T.T. Cockerill. 2008. Life cycle GHG assessment of fossil fuel power
plants with carbon capture and storage. Energy Policy 38:367-380.
Spath, P., and M. Mann. 2000. Life Cycle Assessment of a Natural Gas Combined-Cycle
Power Generation System. NREL/TP-570-27715. National Renewable Energy
Laboratory, Golden, Colo. September.
Spath, P, and M. Mann. 2004. Biomass Power and Conventional Fossil Systems with and
without CO2 Sequestration⎯Comparing the Energy Balance, Greenhouse Gas
Emissions and Economics. NREL/TP-510-32575. National Renewable Energy
Laboratory, Golden, Colo. January.
Spath, P., M. Mann, and D. Kerr. 1999. Life Cycle Assessment of Coal-fired Power
Production. NREL/TP-570-25119. National Renewable Energy Laboratory,
Golden, Colo. June.
Storm van Leeuwen, J.W. Nuclear power⎯The energy balance energy insecurity and
greenhouse gases. 2008. Updated version of “Nuclear power⎯The energy
balance” by J.W. Storm van Leeuwen and P. Smith. 2002. Available at
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Vattenfall AB. 2004. Certified Environmental Product Declaration of Electricity from
Vattenfall´s Nordic Hydropower. Registration No. S-P-00088. Vattenfall AB
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White S.. 1998. Net Energy Payback and CO2 Emissions from Helium-3 Fusion and
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