Impact of Combined Heat and Power
on Energy Use and Carbon Emissions
in the Dry Mill Ethanol Process
U.S. Environmental Protection Agency
Combined Heat and Power Partnership
i CHP
>EPA COMBINED HEAT AMU
POWEFt PARTNERSHIP
Updated
November 2007
For more information about the EPA CHP Partnership,
visit: www.epa.gov/chp.
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EPA Combined Heat and Power Partnership
The EPA CHP Partnership is a voluntary program that seeks to
reduce the environmental impact of power generation by promoting
the use of 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: www.epa.gov/chp. For more information contact
Neeharika Naik-Dhungel at (202) 343-9553 or
naik-dhungel.neeharika@epa.gov.
Report prepared by: Energy and Environmental Analysis, Inc. (www.eea-inc.com) for the U. S.
Environmental Protection Agency, Combined Heat and Power Partnership, November 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 mid 2007, there
were 82 new ethanol plants and twelve expansions under construction, which will add close to 7
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 also 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 for mash cooking, distillation, and evaporation. It is also used
directly in DGS dryers and in thermal oxidizers that destroy the volatile organic compounds
(VOCs) present in the dryer exhaust.
The industry has made great progress in reducing energy consumption since its start in the
1980s; to produce a gallon of ethanol, today's dry mill plants only use about half of the energy
used by the earliest plants.2 Still, natural gas prices are on the rise, and energy costs are
second only to raw material costs in the dry mill process. These factors are driving the industry
to undertake 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
ethanol plant owner and financing groups. CHP is an efficient, clean, and reliable energy
services alternative, based on generating electricity on site. CHP avoids line losses, increases
reliability, and captures 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 by 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 and EPA CHRP data.
2 Huo, H., Wang, M., & Wu, M. Life Cycle and Greenhouse Gas Emissions Impacts of Different Corn Ethanol
Plant Types. Argonne National Laboratory. 2007.
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Figure 1. Total Efficiency Benefits of Combined Heat and Power
Conventional
Generation
Combined
Heat & Power
5 MW fWijwI lias
• Heal
p .,-,
ft>
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
consumed 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 the use of CHP can result in
reductions in total energy use of almost 55 percent over state-of-the-art dry mill ethanol plants
that purchase central station power rather than use CHP. With certain CHP configurations, CO2
emission reductions from using CHP to displace central station power even exceed the CO2
emissions from the CHP system and ethanol plant, resulting in negative net CO2 emissions for
the plant compared with base case conditions.
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 emissions. These 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 levels, and as carbon footprint becomes a critical
industry measure.
CHP is not new at ethanol plants. Five gas turbine CHP systems similar to the cases described
in this paper are currently operating at dry mill ethanol plants in the United States.3 The first
coal-fueled dry mill ethanol plants are just coming online, and at least one includes a steam
Gas turbine CHP systems are installed at Adkins Energy LLC, Lena, Illinois; U.S. Energy Partners, Russell,
Kansas.; Northeast Missouri Grain (POET Macon), Macon, Missouri.; Otter Creek Ethanol (POET Ashton), Ashton,
Iowa; and Missouri Ethanol (POET Laddonia), Laddonia, Missouri.
-------
turbine CHP system similar to the system described in this analysis.4 In addition, a biomass-
fueled CHP system is undergoing startup at an ethanol plant in Minnesota.5
Baseline Energy Consumption Profiles for Dry Mill Ethanol Production Facilities
Dry mill ethanol is the fastest growing market segment in the industry. It is comprised of
dedicated ethanol facilities producing between 20 and more than 100 million gallons (MG) of
ethanol per year. Energy is the second largest production cost 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
byproduct solids. (Dried distilled grains with solubles, or DDGS, are produced by drying the wet
cake left over from the distillation process.) Electricity is used for process motors, grain
preparation, and a variety of plant loads. A typical 50-MG-per-year (MGY) dry mill plant will have
steam loads of 100,000 to 150,000 pounds per hour, 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-MGY 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 and 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 production 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 than for
natural gas systems (0.90 kilowatt-hours [kWh]/gallon versus 0.75 kWh/gallon 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
4 Central Illinois Energy in Canton, Illinois., is a 37 million gallons (MG) per year plant fueled by coal fines and coal. It
incorporates a fluidized bed boiler/steam turbine CHP system.
5 Central Minnesota Ethanol in Little Falls, Minnesota., is installing a biomass gasifier, fluidized bed boiler system with
a steam turbine generator.
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 nonregenerative 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, MG/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 and 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 in Table 1, an analysis was conducted of the
relative energy consumption of conventional, non-CHP, dry mill ethanol boiler plant designs
compared with those incorporating CHP. The analysis was based on state-of-the-art, 50 MGY
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 using the energy consumption assumptions outlined in Table 1. Steam
consumption is based on delivering 150 pounds per square inch gauge (PSIG) saturated steam
to the process (energy input from the boiler of 1,022 Btu [British thermal units] per pound of
steam).
Table 2. Base Case Steam and Electric Demands for 50 Million Gallons per Year Dry Mill
Ethanol Plants
Plant Capacity, MGY
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 three 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.
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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's 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 22.1 MW of power and 100 MMBtu per hour of steam. The electrical 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
30 MW. It does so by producing higher-pressure steam in the HRSG and driving a steam
turbine to generate additional power before sending steam to the production 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 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 onsite, 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
22.1
97%
8,334
184,187
100.1
NA
100.1
834,200
CHP Case 3
Gas
Combined
Cycle
30.0
97%
8,334
250,027
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 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 is needed at the plant, the increases are 62 and 90
percent, respectively.
Table 4. CHP Plant Energy Consumption Comparison—Natural Gas
Characteristics
Plant Capacity, MGY
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
860,000
0
0
1 ,075,000
541 ,500
1,616,500
32,330
CHP Case 1
Gas Turbine
With Duct
Firing
50
4.4
4.0
97%
33,337
4,163
0
834,200
25,800
422,846
718,533
32,250
541 ,500
1,715,129
34,303
CHP Case 2
Gas Turbine
With Export
50
4.4
22.1
97%
184,187
4,163
150,850
834,200
25,800
2,057,103
0
32,250
541 ,500
2,630,853
52,677
CHP Case 3
Combined
Cycle
With Export
50
4.4
30.0
97%
250,027
4,163
216,690
834,200
25,800
2,510,327
0
32,250
541 ,500
3,084,077
67,682
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Table 5 compares the overall plant energy consumption profile of 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, MGY
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 ,570,000
1 ,570,000
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 ,755,000
1 ,570,000
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 ,570,000
1 ,570,000
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 ,755,000
1 ,570,000
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. It depends on the
relative costs to the plant of purchased electricity and fuels; the capital and nonfuel operating
costs of the CHP system; 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. This evaluation includes the effect on reductions in
central station power fuel use and CO2 emissions caused by displacing power purchases with
electricity generated on site 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 megawatt-hour (MWh). Transmission and distribution losses were assumed to be 7
percent based on U.S. Department of Energy estimates of average annual transmission and
-------
distribution system losses.10 CO2 emissions at the ethanol plant were calculated based on 117
pounds of CO2 per MMBtu of natural gas consumed.
As shown in the table, 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 net fuel used to produce a
gallon of ethanol, and associated net CO2 emissions, are further reduced. In Case 3, CHP
reduces total net fuel consumption by 55 percent; CO2 emission reductions from displacing
central station power exceed the CO2 emissions at the plant itself, resulting in negative net CO2
emissions for the CHP system compared with 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
With 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
With Export
2,630,853
52,677
45,688
-1 ,539,633
1,136,908
22,738
153,905
-136,639
17,265
0.69
CHP Case 3
Combined
Cycle
With Export
3,084,077
67,682
45,688
-2,211,628
918,137
78,363
180,419
-198,101
-17,683
-0.77
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. Transmission and distribution 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 approximately 5.6
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.
No transmission and distribution losses were included in the calculation of central station fuel use and CC>2
emissions displaced by power exports from the CHP systems.
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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 use impacts across the
three base cases and five CHP cases. Note that the total fuel consumption—fuel consumed at
the ethanol plant, as well as at the central station power 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 net 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
(Cases 2 and 3), the displaced central station fuel represents a significant credit against
increased fuel use at the plant. The total fuel savings for Cases 2 and 3 are 44 percent and 55
percent, respectively, over the natural gas base case.
10
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Figure 2. Total Net Fuel Consumption for Dry Mill Ethanol Plants—Btu/Gallon
Nat Gas CHP CHP CHP Coal CHP Biomass CHP
Base Case 1 Case 2 Case 3 Base Case 4 Base Case 5
D Central Station Fuel • Plant Fuel ffi Displaced Central Station Fuel
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 facility to produce electricity purchased by the plant—are significantly lower than for the
coal base case. CO2 emissions for the biomass base case are the lowest, consisting 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 Cases 2 and 3—the two natural gas CHP
cases with excess power available for export—represent a significant CO2 savings. Total net
CO2 emissions in Case 2 represent an 87 percent reduction in CO2 emissions compared to the
natural gas base case. Total plant CO2 emissions for Case 3 are actually less than the
displaced central station emissions, resulting in a negative (-0.71 pounds per gallon) net CO2
emissions rate compared to the base case.
Figure 3. Total Net CO2 Emissions for Dry Mill Ethanol Plants—Pounds/Gallon
n
f
E
LLI
r
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