•SERA COMBIHEP HEAT ANC
K3WERP*fiINtflSMIP
Impact of Combined Heat and Power
on Energy Use and Carbon Emissions
in the Dry Mill Ethanol Process
September 2007
For more information about the EPA CHP Partnership, please
visit: www.epa.gov/chp or email: chpteam@epa.gov.
EPA Combined Heat and Power Partnership
-------
EPA CHP Partnership
The EPA CHP Partnership is a voluntary program that seeks to
reduce the environmental impact of power generation by promoting
the use of combined heat and power (CHP). CHP is an efficient,
clean, and reliable approach to generating power and thermal
energy from a single fuel source. CHP can increase operational
efficiency and decrease energy costs, while reducing emissions of
greenhouse gases that contribute to climate change. The
Partnership works closely with energy users, the CHP industry,
state and local governments, and other stakeholders to support the
development of new projects and promote their energy,
environmental, and economic benefits.
The Partnership provides informational resources about CHP
technologies, incentives, emissions profiles, and many other items
on its Web site at: www.epa.gov/chp. For more information contact
Kim Grossman at 202-343-9388 or crossman.kim@epa.gov.
Report prepared by: Energy and Environmental Analysis, Inc. (www.eea-inc.com) for the U. S.
Environmental Protection Agency, Combined Heat & Power Partnership, September 2007.
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Executive Summary
Fuel ethanol is one of the fastest growing segments of U.S. industry. Driven by provisions of the
renewable fuels standard (RFS) in the Energy Policy Act of 2005 that increased the mandated
use of renewable fuels, including ethanol and biodiesel, and a phase-out of methyl tertiary butyl
ether (MTBE) as an oxygenate for reformulated gasoline, production of ethanol has increased
by more than 300 percent since 2000. In 2006 the industry's 110 operating plants produced 4.9
billion gallons of ethanol, an increase of 25 percent over the previous year. At the beginning of
2007, there were 73 new ethanol plants and eight expansions under construction that will add 6
billion gallons of new production capacity by 2009,1 far surpassing the RFS mandate of 7.5
billion gallons in 2012.
Historically, corn ethanol plants are classified into two types: wet milling and dry milling. In wet
milling plants, corn kernels are soaked in water containing sulfur dioxide (SO2), which softens
the kernels and loosens the hulls. Kernels are then degermed, and oil is extracted from the
separated germs. The remaining kernels are ground, and the starch and gluten are separated.
The starch is used for ethanol production. In dry milling plants, the whole dry kernels are milled.
The milled kernels are sent to fermenters, and the starch portion is fermented into ethanol. The
remaining, unfermentable portions are produced as distilled grains and solubles (DGS) and
used for animal feed. Dry mill plants have become the primary production process for fuel
ethanol. All corn ethanol plants that have come online in the past several years are dry milling
plants and the Renewable Fuels Association estimates that essentially all new plants expected
to come online in the next few years will be dry milling plants.
Dry mill ethanol plants have traditionally used natural gas as the process fuel for production.
Natural gas is used to raise steam used for mash cooking, distillation and evaporation, and used
directly in DGS dryers and in thermal oxidizers that destroy the VOCs present in the dryer
exhaust. The industry has made great progress in reducing energy consumption since its start
in the 1980s; today's dry mill plants only use about half of the energy to produce a gallon of
ethanol than those earliest plants.2 Driven by rising natural gas prices and the fact that energy
costs are second only to raw material costs in the dry mill process, the industry is undertaking
further efforts to reduce energy use or to switch from natural gas to other fuels such as coal,
wood chips, or even the use of DGS and other process byproducts.
Along with increased production efficiencies and expanded fuel capabilities, combined heat and
power (CHP) is increasingly being considered as an efficient energy services option by many
owner and financing groups. CHP is an efficient, clean, and reliable energy services alternative,
based on generating electricity on-site to avoid line losses and increased reliability and
capturing much of the heat energy normally wasted in power generation to supply steam and
other thermal needs at the site. CHP systems typically achieve total system efficiencies of 60 to
80 percent compared to only about 50 percent for conventional separate electricity and thermal
energy generation (see Figure 1). By efficiently providing electricity and thermal energy from the
same fuel source at the point of use, CHP significantly reduces the total fuel used to provide
energy services to a business or industrial plant, along with the corresponding emissions of
carbon dioxide (CO2) and other pollutants.
1 Ethanol Industry Outlook 2007, Renewable Fuels Association, February 2007
2 "Life Cycle and Greenhouse Gas Emissions Impacts of Different Corn Ethanol Plants Types", Michael Wang, May
Wu, Hong Huo, Argonne National Laboratory, 2007
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To date, CHP and ethanol industry stakeholders have recognized that the efficiencies of CHP
could further improve energy use patterns of dry mill ethanol plants, but the levels of impact
have been unclear. This paper summarizes an analysis of state-of-the-art natural gas-, coal-,
and biomass-fueled dry mill ethanol plants, comparing energy consumption and CO2 emissions
of the ethanol production process with and without CHP systems. Only the energy consumed in
the dry mill conversion process itself was examined; the analysis does not consider the energy
consumption in growing, harvesting, and transporting the feedstock corn or in transporting the
ethanol product itself. The analysis examines the impact of CHP on total energy consumption,
including the impact on reductions in central station power fuel use and CO2 emissions caused
by displacing power purchases with CHP. The analysis shows that use of CHP can result in
reductions in total energy use of up to 50 percent and reductions in total CO2 emissions of up to
98 percent over state-of-the-art dry mill ethanol plants without CHP.
While fuel selection at new dry mill ethanol plants is increasingly a decision based on
perceptions of future natural gas prices and the cost and availability of alternatives such as coal
or biomass, whatever fuel is used, CHP increases the total energy efficiency of the dry mill
process, providing reductions in both overall fuel use and total CO2 emissions. CHP, using any
of a suite of technologies, can be applied with a variety of fuels to save operating costs for the
user and reduce overall fuel use and CO2. Both factors promise to be important considerations
for the future of ethanol production as low carbon fuel standards are being evaluated at both the
state and federal level and as carbon footprint becomes a critical industry measure. CHP is not
new at ethanol plants. There are currently five gas turbine CHP systems similar to the cases
described in this paper operating at dry mill ethanol plants in the United States.3 The first coal-
fueled dry mill ethanol plants are just coming on line and at least one includes a steam turbine
CHP system similar to the system described in this analysis.4 A biomass-fueled CHP system is
undergoing start-up at an ethanol plant in Minnesota.5
Gas turbine CHP systems are installed at Adkins Energy LLC, Lena, IL; U.S. Energy Partners, Russell, KS;
Northeast Missouri Grain (POET Macon), Macon, MO; Otter Creek Ethanol (POET Ashton), Ashton, IA; and Missouri
Ethanol (POET Laddonia), Laddonia, MO.
4 Central Illinois Energy, Canton, IL - a 37 MMGal/yr plant fueled by coal fines and coal; incorporates a fluidized bed
boiler/steam turbine CHP system.
5 Central Minnesota Ethanol, Little Falls, MN is installing a biomass gasifier, fluidized bed boiler system with a steam
turbine generator.
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Baseline Energy Consumption Profiles for Dry Mill Ethanol Production Facilities
Dry mill ethanol is the fastest growing market segment in the industry and is comprised of
dedicated ethanol facilities producing 20 to more than 100 million gallons per year. Energy is the
second largest cost of production for dry mill ethanol plants, surpassed only by the cost of the
corn itself. Dry mill plants use significant amounts of steam for mash cooking, distillation and
evaporation. Steam or natural gas is also used for drying by-product solids (dried distilled grains
with solubles, or DDGS, is produced by drying the wet-cake leftover from the distillation
process). Electricity is used for process motors, grain preparation, and a variety of plant loads. A
typical 50 million gal/year dry mill plant will have steam loads of 100,000 to 150,000 Ibs/hr and
power demands of 4 to 6 megawatts (MW) depending on its vintage and mix of operations.
Table 1 provides energy consumption estimates (natural gas-, coal- and biomass-fueled) for a
50 million gallon per year state-of-the-art dry mill ethanol plant based on information from
engineering and energy suppliers. The estimates reflect expected energy performance of new
ethanol plants installed in 2006/2007. The assumptions in Table 1 are based on ethanol
production only (e.g., no CO2 recovery) and 100 percent drying of the wet cake for cattle feed
product (DDGS).
The natural gas energy estimates are based on multiple packaged natural gas boilers
generating steam for the process. Natural gas is also used directly in the DDGS dryer, and in
the regenerative thermal oxidizer that destroys the VOCs present in the dryer exhaust. The coal
and biomass system estimates are based on fluidized bed boiler systems that integrate exhaust
from a steam heated DDGS dryer as combustion air to the boiler; in this case, VOC destruction
occurs in the boiler itself and there is no need for a separate thermal oxidizer. The per gallon
electricity consumption is higher for the coal and biomass systems (0.90 kWh/gal versus 0.75
kWh/gal for natural gas) due to an estimated 20 percent additional power requirement for fuel
handling, processing, and boiler ancillaries. The total steam consumption per gallon of ethanol
is higher for the coal and biomass systems as well, reflecting the use of a steam DDGS dryer
instead of a direct-fired system. The efficiency of the biomass fluidized bed boiler is lower than
the coal boiler (72 percent versus 75 percent), reflecting a higher moisture content in biomass
fuels. There is no direct fuel consumption for either a DDGS dryer or a thermal oxidizer in the
coal or biomass-fueled systems.6
6 The configurations evaluated represent typical state-of-the-art dry mill plants for each of the fuels. There are,
however, a number of variations in use. Several natural gas-fueled plants generate a majority of their process steam
using heat recovery boilers on the exhaust of non-regenerative thermal oxidizers. There is at least one coal-fueled
plant that uses natural gas in a DDGS dryer and thermal oxidizer.
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Table 1 - Energy Consumption Assumptions for State-of-the-Art Dry Mill Ethanol Plants7
Plant Capacity, MMGal/yr
Ethanol Yield, Gal/bushel
Operating Hours
Electric Consumption, kWh/Gal
Average Electric Demand, MW
Annual Electric Consumption, MWh
Boiler Type
Boiler Efficiency, percent (HHV8)
Boiler Fuel Use for Process Steam, Btu/Gal
Process Steam Use, MMBtu/hr
Annual Process Steam Use, MMBtu
DDGS Dryer Type
Amount of Wet Cake Dried, percent
DDGS Dryer Fuel Use, Btu/Gal
DDGS Dryer Steam Use, Btu/Gal
Annual DDGS Dryer Fuel Use, MMBtu
Annual DDGS Dryer Steam Use, MMBtu
Thermal Oxidizer
Thermal Oxidizer Fuel Use, Btu/Gal
Annual Thermal Oxidizer Fuel Use, MMBtu
Total Annual Steam Use, MMBtu
Total Annual Boiler Fuel Use, MMBtu
Total Annual Fuel Use, MMBtu
Total Fuel Use, Btu/Gal
Natural Gas-
Fueled Plant
50
2.8
8,592
0.75
4.4
37,500
Packaged
80%
21,500
100.1
860,000
Direct Fired
100%
10,500
NA
525,000
NA
RTO
330
16,500
860,000
1 ,075,000
1,616,500
32,330
Coal-Fueled
Plant
50
2.8
8,592
0.90
5.2
45,000
Fluidized Bed
78%
22,050
100.1
860,000
Steam
100%
NA
14,200
NA
710,000
Boiler
NA
NA
1 ,570,000
2,015,000
2,015,000
40,260
Biomass-
Fueled Plant
50
2.8
8,592
0.90
5.2
45,000
Fluidized Bed
72%
22,050
100.1
860,000
Steam
100%
NA
14,200
NA
710,000
Boiler
NA
NA
1 ,570,000
2,183,000
2,183,000
43,660
References
1
Nat gas: 1,2; Coal: 2,4
Calculated
Calculated
1,2,4,5
4,5
Nat gas: 1,2,3,4; Coal: 2,4,5
Calculated
Calculated
2,5
Calculated
1, 2, 3, 4
4, 5
Calculated
Calculated
2,5
4,5,6
Calculated
Calculated
Calculated
Calculated
Calculated
References for Table 1:
1. "Dry Mill Ethanol Plants", Bill Roddy, ICM, Governors' Ethanol Coalition, Kansas City, Kansas, February 10, 2006
2. Personal Communications with Matt Haakenstad, U.S. Energy Services
3. "Thermal Requirements: Coal vs. Natural Gas", Casey Whelan, U.S. Energy Services, Fuel Ethanol Workshop,
Milwaukee, Wisconsin, June 20, 2006
4. Personal communications with Steffan Mueller, University of Illinois at Chicago; data from Henneman Engineering
5. "Research Investigation for the Potential Use of Illinois Coal in Dry Mill Ethanol Plants", Energy Resources Center,
University of Illinois at Chicago, October 2006
6. Energy and Environmental Analysis, Inc estimates
"State-of-the-art" reflects the energy performance of new dry mill ethanol plants in 2006/2007.
8 All of the efficiencies and energy consumption values quoted in this paper are based on higher heating value (HHV)
fuel consumption, which includes the heat of condensation of the water vapor in the combustion products.
Engineering and scientific literature often use the lower heating value (LHV), which does not include the heat of
condensation of the water vapor in the combustion products. The HHV is greater than the LHV by approximately 10
percent for natural gas, 6 to 8 percent for oil (liquid petroleum products), and 5 percent for coal.
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The Impact of CHP on Plant Energy Consumption Profiles
Based on the energy use assumptions outlined above, an analysis was conducted of the
relative energy consumption of conventional, non-CHP, dry mill ethanol boiler plant designs to
those incorporating CHP. The analysis was based on state-of-the-art 50 million gallons per year
natural gas-, coal-, and biomass-fueled ethanol plants as described above. Three base case
plant designs were considered:
• Natural Gas Base Case - Conventional (non-CHP) natural gas boiler, gas-fired DDGS dryer,
and regenerative thermal oxidizer.
• Coal Base Case - Non-CHP fluidized bed coal boiler with exhaust from a steam-heated
DDGS dryer integrated into the boiler intake for VOC control.
• Biomass Base Case - Non-CHP fluidized bed coal boiler with exhaust from a steam-heated
DDGS dryer integrated into the boiler intake for VOC control.
All three base cases were assumed to operate 24 hours per day, seven days per week, for 51
weeks per year (8,592 hours). Table 2 presents the hourly steam and electric demands of the
three base cases based on the energy consumption assumptions outlined in Table 1. Steam
consumption is based on delivering 150 psig saturated steam to the process (energy input from
the boiler of 1,022 Btu per pound of steam).
Table 2 -Base Case Steam and Electric Demands for 50 Million Gallon per Year Dry Mill
Ethanol Plants
Plant Capacity, MMGal/yr
Operating Hours
Electric Consumption, kWh/Gal
Average Electric Demand, MW
Annual Electric Consumption, MWh
Process Steam Use, MMBtu/hr
Dryer Steam Use, MMBtu/hr
Total Steam Use, MMBtu/hr
Annual Steam Use, MMBtu
Natural Gas
Base Case
50
8,592
0.75
4.4
37,500
100.1
NA
100.1
860,000
Coal
Base Case
50
8,592
0.90
5.2
45,000
100.1
82.6
182.6
1 ,570,000
Biomass
Base Case
50
8,592
0.90
5.2
45,000
100.1
82.6
182.6
1 ,570,000
Five CHP system configurations were evaluated and compared to the base case non-CHP
ethanol plants:
• Natural Gas CHP
Case 1: Gas turbine/supplemental-fired heat recovery steam generator (HRSG) - electric
output sized to meet plant demand, supplemental firing needed in the HRSG to
augment steam recovered from the gas turbine exhaust.
-------
Case 2: Gas turbine with power export - thermal output sized to meet plant steam load
without supplemental firing, excess power generated for export.
Case 3: Gas turbine/steam turbine with power export (combined cycle) - thermal output
sized to meet plant steam load without supplemental firing, steam turbine added to
generate additional power from high pressure steam before going to process,
maximum power generated for export.
• Coal CHP
Case 4: High pressure fluidized bed coal boiler with steam turbine generator - exhaust from
steam-heated DDGS dryer integrated into the boiler intake for combustion air and
VOC destruction.
• Biomass CHP
Case 5: High pressure fluidized bed biomass boiler with steam turbine generator - exhaust
from steam-heated DDGS dryer integrated into the boiler intake for combustion air
and VOC destruction.
Table 3 provides the CHP system descriptions and performance characteristics assumed for the
analysis. Note that in Case 1—the gas turbine sized to meet the plant electricity load—the
exhaust from the gas turbine can only provide about 23 percent of the plant's steam needs. A
duct burner in the HRSG is used to provide supplemental heat to generate the additional steam
at high efficiency (approaching 90 percent). In Cases 2 and 3, the system is sized to meet the
thermal needs of the plant without supplemental firing. In Case 2, the simple cycle gas turbine
produces 20.6 MW of power and 100 MMBtu/hr of steam. The MW output far exceeds the
average 4.4 MW power requirements of the plant, meaning that excess power would need to be
exported to the grid. This configuration might be installed by a third party service provider, or as
a joint venture between an ethanol plant and the servicing utility. The Case 3 combined cycle
configuration further increases the power output of the CHP system to 27.5 MW by producing
higher pressure steam in the HRSG and driving a steam turbine to generate additional power
before sending the steam to the process at 150 psig. Again, this configuration might be installed
by a third party energy provider or a utility-ethanol plant joint venture.
The sizes of the coal- and biomass-fueled steam turbine systems are set by the steam demand
and power requirements of the plant. The CHP systems analyzed consist of 180,000 pounds
per hour fluidized bed boilers producing steam at pressures and temperatures higher than the
process requirements (600 psig and 600°F). The entire steam output of the boilers enters back
pressure steam turbines where 5.0 MW of electricity is generated before the steam exits the
turbine at the 150 psig pressure conditions required for the process.9 The capacity of the steam
turbine generator is approximately 95 percent of the average plant power demand, ensuring that
all generated power can be used on site.
9 Additional power could be generated in Cases 4 and 5 with higher pressure boilers. Power output was limited in
these cases to ensure all output could be used on-site and to minimize incremental boiler costs over the base cases
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Table 3 - CHP Case Descriptions
CHP System
Net Electric Capacity, MW
System Availability, percent
Annual Operating Hours
Annual Electric Generation, MWh
CHP Steam Generation, MMBtu/hr
Supplemental Firing Steam, MMBtu/hr
Process Steam Generation, MMBtu/hr
Annual Process Steam Generation,
MMBtu
CHP Case 1
Gas
Turbine/Fired-
HRSG
4.0
97%
8,334
33,337
22.5
77.6
100.1
834,200
CHP Case 2
Gas
Turbine/HRSG
20.6
97%
8,334
171,685
100.1
NA
100.1
834,200
CHP Case 3
Gas
Combined
Cycle
27.5
97%
8,334
229,192
100.1
NA
100.1
834,200
CHP Case 4
Coal
Boiler/Steam
Turbine
5.0
95%
8,334
40,812
204.3
NA
182.6
1 ,521 ,800
CHP Case 5
Biomass
Boiler/Steam
Turbine
5.0
95%
8,334
40,812
204.3
NA
182.6
1 ,521 ,800
Table 4 compares the overall plant energy consumption profile of the three natural gas CHP
cases to the natural gas base case. All three CHP cases increase the total fuel use at the plant,
but plant electricity purchases are reduced by 89 percent. In Case 1—the gas turbine sized to
meet the plant electricity load—the fuel use increase is only marginal: about 6 percent more fuel
use than the base case. In Cases 2 and 3 where much more power is generated than needed at
the plant, the increases are 62 and 92 percent respectively.
Table 4 - CHP Plant Energy Consumption Comparison - Natural Gas
Characteristics
Plant Capacity, MMgal/yr
Average Electric Demand, MW
CHP Capacity, MW
CHP Availability, percent
Electric Generated, MWh
Electric Purchased, MWh
Electric Exported, MWh
Annual CHP Steam, MMBtu
Annual Boiler Steam, MMBtu
CHP Turbine Fuel Use, MMBtu
Duct Firing Fuel Use, MMBtu
Boiler Fuel Use, MMBtu
Dryer/TO Fuel Use, MMBtu
Total Plant Fuel Use, MMBtu
Total Plant Fuel Use, Btu/Gal
Gas Base
Case
no CHP
50
4.4
0
n/a
0
37,500
0
0
860
0
0
1 ,075,000
541 ,500
1,616,500
32,330
CHP Case 1
Gas Turbine
w/Duct Firing
50
4.4
4.0
97%
33,337
4,163
0
834
26
422,846
718,533
32,250
541 ,500
1,715,129
34,303
CHP Case 2
Gas Turbine
w/ Ex port
50
4.4
20.6
97%
171,685
4,163
138,348
834
26
2,048,218
0
32,250
541 ,500
2,621 ,968
52,434
CHP Case 3
Combined
Cycle
w/ Ex port
50
4.4
27.5
97%
229,192
4,163
195,855
834
26
2,535,416
0
32,250
541 ,500
3,109,166
62, 183
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Table 5 compares the overall plant energy consumption profile of both the coal and biomass
base cases to their respective CHP cases. Again, both CHP cases increase the total fuel use at
the plant to provide the additional energy contained in high pressure steam that will be turned
into power in the steam turbine. Plant electricity purchases are reduced by 93 percent for both
cases.
Table 5 - CHP Plant Energy Consumption Comparison - Coal and Biomass
Characteristics
Plant Capacity, MMgal/yr
Average Electric Demand, MW
CHP Capacity, MW
CHP Availability, percent
Electric Generated, MWh
Electric Purchased, MWh
Electric Exported, MWh
Annual Boiler Steam, MMBtu
Annual Process Steam, MMBtu
Boiler Fuel Use, MMBtu
Dryer/TO Fuel Use, MMBtu
Total Plant Fuel Use, MMBtu
Total Plant Fuel Use, Btu/Gal
Coal Base
Case
no CHP
50
5.2
0
n/a
0
45,000
0
1,570
1,570
2,015,026
0
2,015,026
40,300
Case 4
Coal CHP
Boiler/ Steam
Turbine
50
5.2
5.0
95%
40,812
4,188
0
1,755
1,570
2,250,313
0
2,250,313
45,005
Biomass Base
Case
no CHP
50
5.2
0
n/a
0
45,000
0
1,570
1,570
2,182,944
0
2,182,994
43,660
Case 5
Biomass CHP
Boiler/ Steam
Turbine
50
5.2
5.0
95%
40,812
4,188
0
1,755
1,570
2,437,839
0
2,437,839
48,760
The economic value of CHP is a trade-off between capital costs, fuel costs at the plant, and
decreased electricity purchases from the utility. While CHP increases the amount of fuel used
at the plant in each of the CHP cases, it significantly reduces purchased electricity
requirements. Whether this trade-off makes sense on an economic basis is site specific and
depends on the relative prices of purchased electricity and fuels to the plant, the capital and
non-fuel operating costs of the CHP systems, and the value of ancillary services such as
enhanced power reliability to the plant operator or the value of exported power as in Cases 2
and 3.
The Impact of CHP on Total Energy Use and CO2 Emissions
From an overall energy and environmental policy perspective it is essential to examine the
impact of CHP on total energy consumption, including the impact on reductions in central station
power fuel use and CO2 emissions caused by displacing power purchases with electricity
generated onsite by CHP. Table 6 compares the total energy consumption of the three natural
gas CHP cases with the base case plant and central station fuel consumption. Central station
fuel use and CO2 emissions were calculated based on the 2007 eGRID U.S. average fossil heat
rate equal to 10,215 Btu/kWh and average fossil CO2 emissions of 1,867 pounds per MWh.
Transmission and distribution (T&D) losses were assumed to be 7 percent based on U.S.
Department of Energy (DOE) estimates of average annual T&D system losses. CO2 emissions
at the ethanol plant were calculated based on 117 pounds of CO2 per MMBtu of natural gas
consumed. As shown, CHP reduces both the total energy used by the dry mill ethanol process
and the total CO2 emissions. In Case 1, overall fuel use is reduced by 13 percent on a Btu per
-------
gallon basis, and CO2 emissions are reduced by 21 percent on a pound per gallon basis. As
more central station power is displaced in Cases 2 and 3, overall fuel use and CO2 emissions
are further reduced. The maximum power output of Case 3 reduces overall fuel consumption to
produce a gallon of ethanol from the dry mill process by 50 percent and CO2 emissions by
almost 98 percent compared to base case conditions.
Table 6 - CHP Total Energy Consumption Comparison - Natural Gas
Characteristics
Plant Fuel Use
Total Plant Fuel Use, MMBtu
Total Plant Fuel Use, Btu/Gal
Central Station Fuel Use
Purchased Power - MMBtu
Export Power - MMBtu
Total Net Fuel Use, MMBtu
Net Fuel Use, Btu/Gal
Plant CO2 Emissions, Tons/yr
Central Station CO2 Emissions, Tons/yr
Net CO2 Emissions, Tons/yr
Net CO2 Emissions, Ib/Gal
Base Case
no CHP
1,616,500
32,330
41 1 ,548
0
2,028,048
40,560
94,565
37,641
132,206
5.29
CHP Case 1
Gas Turbine
w/Duct Firing
1,715,129
34,303
45,688
0
1,760,817
35,275
100,335
4,179
104,514
4.18
CHP Case 2
Gas Turbine
w/ Ex port
2,621 ,968
52,434
45,688
(1,518,322)
1,149,334
22,990
153,385
(124,970)
28,416
1.14
CHP Case 3
Combined
Cycle
w/ Ex port
3,109,166
62,783
45,688
(2,149,431)
1 ,005,422
20,110
181,886
(182,830)
3,235
0.73
Table 7 compares the total energy consumption of the coal and biomass CHP cases with their
respective base cases. Central station fuel use and CO2 emissions were again based on the
2007 eGRID U.S. average fossil heat rate equal to 10,215 Btu/kWh and average fossil CO2
emissions of 1,867 pounds per MWh. T&D losses were assumed to be 7 percent based on DOE
estimates of average annual losses. CO2 emissions at the ethanol plant were calculated based
on industry-accepted values of 220 pounds of CO2 per MMBtu of coal. Biogenic biomass is
considered carbon neutral, neither adding nor subtracting carbon emissions from the carbon
cycle, and was assumed to have zero CO2 emissions. As shown, CHP again reduces both the
total energy used by the dry mill ethanol process and the total CO2 emissions. CHP reduces
overall fuel use by 9 percent and CO2 emissions by almost 6 percent in the case of coal. CHP
provides a total fuel reduction of 8 percent in the case of biomass-fueled ethanol production and
results in CO2 reductions of 91 percent.
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Table 7 - CHP Total Energy Consumption Comparison - Coal and Biomass
Characteristics
Plant Fuel Use
Total Plant Fuel Use, MMBtu
Total Plant Fuel Use, Btu/Gal
Central Station Fuel Use
Purchased Power - MMBtu
Export Power - MMBtu
Total Net Fuel Use, MMBtu
Net Fuel Use, Btu/Gal
Plant CO2 Emissions, Tons/yr
Central Station CO2 Emissions, Tons/yr
Net CO2 Emissions, Tons/yr
Net CO2 Emissions, Ib/Gal
Coal Base
Case
no CHP
2,015,026
40,300
493,858
0
2,508,884
50,778
221 ,653
45,169
266,822
10.67
Case 4
Coal CHP
Boiler /Steam
Turbine
2,250,313
45,005
45,962
0
2,296,275
45,925
247,534
4,204
251 ,738
10.07
Biomass Base
Case
no CHP
2,182,994
43,660
493,858
0
2,676,852
53,540
0
45,169
45,169
1.81
Case 5
Biomass CHP
Boiler/ Steam
Turbine
2,437,839
48,760
45,962
0
289,801
49,675
0
4,204
4,204
0.17
Conclusions
As shown above, use of CHP can lower the overall fuel use and CO2 emissions attributable to
ethanol production at dry mill plants. Figure 2 compares the total fuel impacts graphically. Note
that the total fuel consumption—fuel consumed at the ethanol plant as well as at the central
station power generating facility to produce electricity purchased by the plant—is less for the
base case natural gas ethanol plant than for either the coal or biomass base cases. In all cases,
fuel consumption at the plant increases with the use of CHP. However, total fuel consumption is
reduced as electricity generated by the CHP systems displaces less efficient central station
power. In the two natural gas CHP cases with excess power available for export, the displaced
central station fuel use represents a significant credit against increased fuel use at the plant.
The total fuel savings for Cases 2 and 3 are 43 percent and 50 percent respectively over the
natural gas base case.
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Figure 2 - Total Fuel Consumption for Dry Mill Ethanol Plants - Btu/Gallon
c
_0
S
w u
D
1
i— jnnnn
.mnm-
—
—
| D Plant Energy D Cental Station Energy D Displaced Cenlral Station Energy |
Figure 3 compares the impact of CHP on total CO2 emissions. Total CO2 emissions for the
natural gas base case—CO2 emissions at the ethanol plant as well as at the central station
power generating facility to produce electricity purchased by the plant—are significantly lower
than the coal base case. CO2 emissions for the biomass base case are the lowest, comprised
essentially of the central station emissions to provide purchased power to the plant. Total CO2
emissions are reduced for all CHP cases compared to their respective base case plants. Again,
displaced central station emissions for the two natural gas CHP cases with excess power
available for export represent a significant CO2 savings. Total CO2 emissions in Cases 2 and 3
represent reductions of 78 percent and 97.5 percent of the natural gas base case total CO2
emissions respectively. The net carbon footprints of these two export cases are comparable to
those of the biomass base case and biomass CHP case.
Figure 3 - Total CO2 Emissions for Dry Mill Ethanol Plants - Pounds/Gallon
12
1 -4
UJ
8,
• -12
I Plant CQ2 D Central Station OQ2 D Displaced Cental SaHion CX321
11
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