&EPA COMBINEP HEAT ANO
KJWERPARINEflSHIP
"
An Assessment of the Potential for
Energy Savings in Dry Mill
Ethanol Plants from the Use of
Combined Heat and Power (CHP)
Prepared for:
U. S. Environmental Protection Agency
Combined Heat & Power Partnership
July 2006
Prepared by:
Energy and Environmental Analysis, Inc.
www.eea-inc.com
For more information about the EPA CHP Partnership, please
visit: www.epa.gov/chp or email: chpteam@epa.gov.
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DRAFT
Executive Summary
Fuel ethanol is one of the fastest growing segments of the U.S. chemical industry. In 2005 the industry's
ninety operating plants produced almost 4 billion gallons of ethanol. Provisions in the Energy Policy Act
of 2005 are expected to drive industry expansion even further, providing a market for nearly 8 billion
gallons of ethanol by 2012. The industry is poised to invest an estimated $6 billion in new plants and
expansions to build the required capacity to meet this market demand.
One of the more controversial issues related to expanded use of fuel ethanol is the question of the "net
energy balance" of the total ethanol production process; i.e., is more energy used to grow, transport and
process the raw material into ethanol than is contained in the ethanol itself? Numerous researchers have
studied this question and, based on the most recent results, a consensus is growing that the production of
ethanol is indeed a positive net energy generator. Today's higher corn yields, lower energy use per unit
of output in the fertilizer industry, and advances in ethanol process technologies have greatly improved
the energy efficiency of producing dry corn mill ethanol (the primary production path for fuel ethanol)
compared with just a decade ago1'2.
Driven by rising energy prices and the fact that energy costs are second only to raw material costs in the
dry mill ethanol industry, the industry has continued to improve its energy efficiency profile. Further
efficiencies in the ethanol production process have been documented, and the industry has expanded its
fuel options as well; where almost all of the dry mill plants were natural gas based five years ago, there
are a number of plants now under construction based on coal and biomass fuels.
Along with increased production efficiencies and expanded fuel capabilities, combined heat and power
(CHP) is increasingly being considered as a main stream option by many owner and financing groups3.
The efficiencies of CHP can further improve the net energy balance of dry mill ethanol plants, but the
level of improvement has been unclear. This paper summarizes an analysis of state of the art natural
gas- and coal-based dry mill ethanol plants, comparing energy consumption of the ethanol production
process with and without CHP systems. Only the energy consumption in the dry mill conversion process
itself was evaluated; the analysis did not considerthe energy consumption in growing, harvesting and
transporting the feedstock corn or in transporting the ethanol product itself.
Table 1 summarizes the results of the analysis based on the energy consumption patterns of new natural
gas and coal dry mill ethanol plants producing 50 million gallons of fuel ethanol per year. As shown in the
table, while CHP increases the consumption of fuel at the plant itself, it reduces the amount of electricity
purchased from the grid. Total fuel consumption for producing ethanol - considering both fuel use at the
ethanol plant and fuel use at the central station power generation plant - is reduced with the use of CHP.
Reductions in total fuel use are over 12% in the natural gas case and 10% in the coal case.
1 Researchers at Argonne National Laboratory estimate that, based on farming and ethanol production practices of
2001, 0.75 Btu of fuel was consumed to generate 1.0 Btu of dry corn mill ethanol (including fuel used in fertilizer
production, farming, transport of corn to the mill, the ethanol production process, and transport of ethanol to market -
Michael Wang, "Energy and Greenhouse Gas Emissions Results of Fuel Ethanol", presentation to the Governors'
Ethanol Coalition, Kansas City, KS, February 2006.
2 Hosein Shapouri, James Duffield, Michael Wang, "The Energy Balance of Corn Ethanol: An Update", USDA
Agricultural Economic Report Number 813, July 2002.
Combined heat and power (CHP) systems produce both electricity and thermal energy from a single fuel at or near
the consumer. These efficient systems recover heat that normally would be wasted in the generation of electricity,
and save the fuel that would otherwise be used to produce heat or steam for the site.
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DRAFT
Figure 1 - Summary of Energy Consumption in the Dry Mill Ethanol Process - With and Without
CHP
Nominal Capacity, MMGal/yr
Ethanol Yield, Gallons/bushel
Electric Consumption, kWh/Gal
Annual Electric Consumption, kWh
Average Electric Demand, MW
CHP System
CHP Capacity, MW
Purchased Electricity, MWh
Generated Electricity, MWH
Plant Fuel Consumption, MMBtu/yr
Plant Fuel Consumption, Btu/Gal Ethanol
Central Station Fuel Use, MMBtu/yr
Total Fuel Use (Plant and Central Station), MMBtu/yr
Reduction in Total Fuel Use with CHP, %
Natural Gas -
no CHP
50
2.8
0.75
37,500,000
4.4
None
0
37,500
0
1,616,500
32,330
419,156
2,035,656
Natural Gas -
w/CHP
50
2.8
0.75
37,500,000
4.4
Gas Turbine
w/Fired HRSG
4.0
4,850
32,650
1 ,735,769
34,715
54,216
7,789,985
72.7%
Coal -
no CHP
50
2.8
0.87
43,500,000
5.1
None
0
43,500
0
2,012,821
40,256
486,231
2,499,052
Coal -
w/CHP
50
2.8
0.87
43,500,000
5.1
Boiler/Steam
Turbine
4.8
39,415
4,085
2,203,861
44,077
45,664
2,249,525
70.0%
Baseline Energy Consumption Profiles for Dry Mill Corn 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 150 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 solids or DDGS). 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 MW depending on its vintage and
mix of operations. The industry is expected to consume 250 to 290 trillion Btus of fuel and 7.5 to 8.5
billion kWh of electricity annually by 2012.
Table 2 provides energy consumption estimates (natural gas- and coal-based) 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. The
assumptions in Table 1 are based on ethanol production only (e.g., no CO2 recovery) and 100% drying of
the wet cake for cattle feed product (DDGS).
The natural gas values 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 system estimates are based on a fluidized
bed boiler system that integrates 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 system (0.87 kWh/gal versus 0.75
kWh/gal for natural gas) due to an estimated 15 to 20% additional power requirements for fuel handling
and processing4. The total steam consumption per gallon of ethanol is higher for the coal system as well,
For comparison, the USDA economic report (reference 2) used an average electricity consumption of 1.09 kWh/gal
for 2001.
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DRAFT
reflecting the use of a steam DDGS dryer instead of a fuel-fired system. There is no direct fuel
consumption for either a DDGS dryer or a thermal oxidizer in the coal-based system.
Table 2 - Energy Consumption Assumptions for State-of-the-Art Dry Mill Ethanol Plants - 20065
Nominal Capacity, MMGal/yr
Ethanol Yield, Gallons/bushel
Electric Consumption, kWh/Gal
Annual Electric Consumption, kWh
Boiler Type
Boiler Efficiency, HHV
Boiler Fuel Consumption for Process Steam, Btu/Gal
Annual Process Steam Consumption, MMBtu
Fuel Consumption for DDGS Dryer, Btu/Gal
Steam Consumption for DDGS Dryer, Btu/Gal
Annual Fuel Consumption for DDGS Dryer, MMBtu
Annual Steam Consumption for DDGS Dryer, MMBtu
Fuel Consumption for Thermal Oxidizer, Btu/Gal
Total Annual Fuel Consumption for Thermal Oxidizer, MMBtu
Total Annual Steam Consumption, MMBtu
Total Annual Boiler Fuel Consumption, MMBtu
Total Annual Fuel Consumption, MMBtu
Total Fuel Consumption, Btu/Gal
Natural Gas-
Based Plant
50
2.8
0.75
37,500,000
Packaged
80%
21,500
860,000
10,500
N/A
525,000
N/A
330
16,500
860,000
1,075,000
1,616,500
32,330
Coal-Based
Plant
50
2.8
0.87
43,500,000
Fluidized Bed
78%
22,050
860,000
N/A
14,200
N/A
710,000
N/A
N/A
1 ,570,000
2,012,821
2,012,821
40,256
References
1
Natural Gas: 1, 2; Coal: 2, 4
Calculated
1, 2,4
5
Natural Gas: 1,2,3, 4; Coal: 2, 4
Calculated
1, 2, 3, 4
4
Calculated
Calculated
4, 5
Calculated
Calculated
Calculated
Calculated
References:
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. Energy and Environmental Analysis, Inc estimates
The Impact of CHP on Energy Consumption Profiles
Based on the energy consumption assumptions outlined above, an analysis was conducted of the relative
energy consumption of dry mill ethanol plants incorporating CHP compared to conventional non-CHP
boiler plant designs. The analysis was based on state-of-the-art 50 million gallons/year natural gas- and
coal-based ethanol plants described above. Two 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.
' "State of the Art" reflects the energy performance of new dry mill ethanol plants in 2006
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DRAFT
Both base cases were assumed to operate 24 hours per day, seven days a week, for 51 weeks a year
(8592 hours). Table 3 presents the hourly steam and electric demands of the two 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 3 -Steam and Electric Demands for 50 Million Gallon per Year Dry Mill Ethanol Plants
Nominal Capacity MMGal/yr
Annual Operating Hours
Electric Consumption, kWh/Gal
Annual Electric Consumption, kWh
Average Electric Demand, MW
Total Annual Steam Consumption, MMBtu
Hourly Steam Consumption, MMBtu/hr
Hourly Steam Consumption, Ibs/hr
Natural Gas Base
Case
50
8592
0.75
37,500,000
4.4
860,000
100.1
97,938
Coal Base Case
50
8592
0.87
43,500,000
5.1
1,570,000
182.7
178,795
Two CHP plant designs were evaluated:
• Natural Gas CHP - Gas Turbine CHP with a supplementary-fired heat recovery steam generator
(HRSG), natural gas-fired DDGS dryer, and a natural gas-fired regenerative thermal oxidizer.
• Coal CHP - High pressure fluidized-bed coal boiler with steam turbine generator, with exhaust from
steam-heated DDGS dryer integrated into the boiler intake for combustion air and VOC destruction.
Table 4 provides the CHP system descriptions and performance characteristics assumed for the analysis.
Table 4 - CHP System Description
CHP System
Net Electric Capacity, MW
System Availability, %
Annual Operating Hours (8592 hours x 95%)
Annual Electricity Generated, kWhs
Natural Gas CHP
Gas Turbine/HRSG
4.0
95%
8,162
32,650,000
Coal CHP
Boiler/Steam Turbine
4.8
95%
8,162
39,415,000
There are currently four gas turbine CHP systems similar to the system described in this paper operating
at dry mill ethanol plants in the United States6. The gas turbine system considered in this analysis was
sized to ensure that all generated power would be used on-site (the CHP system capacity was limited to
90% of the average plant electric demand). Gas turbine performance was based on a Solar Turbines
Centaur 50. Since a 4.0 MW gas turbine will not produce enough steam in an unfired HRSG to meet the
plant steam requirements outlined in Table 2 (only about 20% of the plant's 100.1 MMBtu/hr steam
demand can be supplied with the turbine exhaust itself), supplementary firing was incorporated into the
design. Steam generation efficiency for the supplemental burner was assumed to be 90%.
Gas turbine CHP systems are installed at Adkins Energy LLC, Lena, IL; U.S. Energy Partners, Russell, KS;
Northeast Missouri Grain, Macon, MO; and Otter Creek Ethanol, Ashton, IA.
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DRAFT
The first coal based dry mill ethanol plants are just coming on line in 2006. At least one includes a steam
turbine CHP system similar to the system described in this analysis7. The size of the coal-based steam
turbine system is set by the steam demand of the plant. The CHP system analyzed consists of an
180,000 pound per hour fluidized bed boiler producing steam at pressures and temperatures higher than
the process requirements (650 psig and 600 F). The entire steam output of the boiler enters a back
pressure steam turbine where 4.8 MW of electricity is generated before the steam exits the turbine at the
150 psig pressure required for the process. The capacity of the steam turbine generator is approximately
94% of the average plant power demand, ensuring that all generated power can be used on-site.
Table 5 provides detailed performance and output characteristics of the gas turbine based CHP system
and compares purchased electricity use and fuel use with the base case non-CHP natural gas ethanol
plant. Based on the system performance assumptions outlined above, the gas turbine CHP system
produces about 87% of the plant's total annual electricity needs and 95% of the plant's steam needs.
While the CHP system displaces 1,021,250 MMBtu/yr of natural gas in the boiler, it consumes 414,128
MMBtu/yr in the gas turbine and an additional 726,931 MMBtu/yr in the HRSG supplemental burner.
Overall natural gas use at the plant increases from 1,616,500 MMBtu/yr in the non-CHP base case to
1,735,769 MMBtu/yr with CHP. Process fuel consumption per gallon of ethanol product increases from
32,330 Btu/gallon to 34,715 Btu/gallon. However, the CHP system displaces 32,650 MWh/yr of
purchased electricity. Assuming an average central station generating efficiency of 33% and average
transmission and distribution system losses of 7.5% (resulting in a net central station generating
efficiency of 30.5%), the CHP system displaces 364,950 Btu/yr of central station generation fuel. When
central station fuel consumption is added to the ethanol plant fuel consumption, total fuel use (fuel
consumed at the ethanol plant and at the central power plant) is reduced with the CHP system by over
12% (2,035,665 MMBtu/yr for the non-CHP base case versus 1,789,986 MMBtu/yr for the gas turbine
CHP system).
Table 6 provides detailed performance and output characteristics of the coal boiler/steam turbine based
CHP system and compares purchased electricity use and fuel use with the base case non-CHP coal
ethanol plant. Based on the system performance assumptions outlined above and in Table 5, the steam
turbine CHP system produces about 91% of the plant's total annual electricity needs. The CHP system
uses about 9.5% additional coal over the base case in order to provide higher pressure and temperature
steam for the turbine generator. Overall coal use at the plant increases from 2,012,821 MMBtu/yr in the
non-CHP base case to 2,203,861 MMBtu/yr with CHP. Process fuel consumption per gallon of product
increases from 40,256 Btu/gallon to 44,077 Btu/gallon. However, the CHP system displaces 39,415
MWh/yr of purchased electricity. Again assuming overall average central station delivered efficiency of
30.5%, the CHP system displaces 440,567 Btu/yr of central station generation fuel. When central station
fuel consumption is added to the ethanol plant fuel consumption, total fuel use is reduced by 10% with the
CHP system (2,499,051 MMBtu/yr for the non-CHP base case versus 2,249,525 MMBtu/yr for the steam
turbine CHP system).
7 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.
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DRAFT
Table 5 - Energy Comparison of Natural Gas-Based Ethanol Plant - With and Without CHP
Plant Data
Plant Capacity, MMgal/yr
Annual Plant Shutdown, Days
Operating Hours
Electric Use, kWh/gal
Electric Use, MWh/yr
Average Electric Demand, MW
Total Steam Demand, Ib/hr (based on 21 ,500 boiler fuel use/gal)
Total Steam Demand, Ib/yr
Steam Temperature, F
Steam Pressure, psig
Steam Enthalpy, Btu/lb
Steam Energy Gain in Boiler, Btu/lb (175 Btu/lb condensate return)
Boiler Efficiency, %
Boiler Fuel, MMBtu/yr (21,500 Btu/gal)
Boiler Steam Output, MMBtu/yr
Boiler Steam Output, MMBtu/hr
Dryer Fuel, MMBtu/yr (10,500 Btu/Gal - 100% DDGS)
OxidizerType
Thermal Oxidizer Fuel, MMBtu/yr (330 Btu/gal)
Gas Turbine Electric Capacity, MW
CHP Net Electric Efficiency, %
CHP System Availability, %
CHP Operating Hours
Gas Turbine Fuel Input, MMBtu/hr
Gas Turbine Fuel Input, MMBtu/yr
HRSG Burner Efficiency, %
HRSG Fuel Input, MMBtu/hr
HRSG Fuel Input, MMBtu/yr
Unfired CHP Steam Output, MMBtu/hr
Total CHP Steam Output, MMBtu/hr
Total CHP Steam Output, MMBtu/yr
CHP Power Generated, MWh/yr
Purchased Power, MWh/yr
Total Plant Fuel Use, MMBtu/yr
Btu Plant Fuel/Gal Ethanol
Average Central Station Generation Efficiency - Delivered, %
Central Station Fuel Use, Mbtu/yr
Total Fuel Use (Plant and Central Station), MMBtu/yr
Natural Gas Base Case
Gas Boiler wo/CHP
50
7
8592
0.75
37,500
4.4
97,938
841,487,280
365
150
1,197
1,022
80.0%
1 ,075,000
860,000
100.1
525,000
Regenerative
16,500
.
-
-
-
0
0
-
0
0
0
0
0
0
37,500
1,616,500
32,330
30.5%
419.165
2,035,665
Natural Gas CHP
Gas Turbine CHP with
Fired HRSG
50
7
8592
0.75
37,500
4.4
97,938
841,487,280
365
150
1,197
1,022
80.0%
53,750
43,000
100.1
525,000
Regenerative
16,500
4.0
26.9%
95%
8,162
50.7
414,128
90.0%
89.0
726,391
20.0
100.1
817,000
32,650
4,850
1,735,769
34,715
30.5%
54.216
1,789,986
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DRAFT
Table 6 - Energy Comparison of Coal-Based Ethanol Plant - With and Without CHP
Plant Data
Plant Capacity, MMgal/yr
Annual Plant Shutdown, Days
Operating Hours
Electric Use, (0.75 kWh/Gal + 15%
Electric Use, MWh/yr
Electric Demand, MW
Steam Use, Ibs/hr - Process
Steam use, Ibs/hr - Dryer (based on
Steam Use, Ibs/yr
Steam Temperature, F
Steam Pressure, psig
Steam Enthalpy, Btu/lb
Steam Energy Gain in Boiler, Btu/lb
Boiler Efficiency, %
Boiler Fuel, MMBtu/yr
Steam Output, MMBtu/yr
Steam Output, MMBtu/hr
Dryer Fuel, MMBtu/yr
Oxidizer Type
Thermal Oxidizer Fuel, MMBtu/yr
parasitic)
14,200Btu/Gal)
Steam Turbine Electric Capacity, MW
CHP System Availability, %
CHP Operating Hours
CHP Power Generated, MWh/yr
Purchased Power, MWh/yr
Total Plant Fuel Use, MMBtu/yr
Btu Plant Fuel/Gal Ethanol
Average Central Station Generation
Central Station Fuel Use, Mbtu/yr
Efficiency - Delivered, %
Total Fuel Use (Plant and Central Station), MMBtu/yr
Coal Base Case
Coal Boiler wo/CHP
w/lntegral VOC and
Steam Dryer
50
7
8592
0.87
43,500
5.1
97,938
80,856
1,536,203,523
365
150
1,197
1,022
78.0%
2,012,821
1,570,000
182.7
0
None
0
-
-
-
0
43,500
2,012,821
40,256
30.5%
486.231
2,499,051
Coal CHP Case
Coal Boiler w/CHP
w/lntegral VOC and
Steam Dryer
50
7
8592
0.87
43,500
5.1
97,938
80,856
1 ,536,203,523
600
650
1,294
1,119
78.0%
2,203,861
1,719,012
200.1
0
None
0
4.8
95%
8,162
39,415
4,085
2,203,861
44,077
30.5%
45.664
2,249,525
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