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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power
Generation
Written by Mark Mba Wright
October 14, 2010
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Executive Summary
The purpose of this report is to provide an analysis of the feasibility and economics of using biomass
feedstock to displace coal-‐fired heat and power generation in Iowa, with an emphasis on biomass
generation that is economically and environmentally sustainable.
Biomass includes a large variety of feedstock with varying compositions and energy properties.
There are various types of feedstock that provide attractive opportunities to replace fossil fuels in heat
and power applications. The main advantage of biomass feedstock is that they provide an opportunity to
reduce greenhouse gas emissions. In locations where low-‐cost feedstock is available, biomass can also
serve as an economical substitute to coal and natural gas. Iowa generates approximately 68.3 million
tons of stover per year. Some of this biomass could be harnessed to generate heat and power. Wood
and wood-‐derived residues are not a major Iowa resource. Therefore, woody biomass is included in this
report only for comparison purposes.
Dedicated biomass combined heat and power (CHP) systems are generally classified as direct
combustion, gasification, or anaerobic digestion. Direct combustion generates hot gas that can be used
to raise steam for heat or power. Gasification systems generate a hot, combustible gas that can be
combined with both a gas turbine and a steam cycle. Anaerobic digestion systems generate methane
suitable as a natural gas substitute. Dedicated systems are attractive for scenarios where low-‐cost
feedstock is available. Alternatively, biomass can be integrated into existing coal plants.
Biomass co-‐firing with coal can be done in one of three ways: simultaneously, separately, or via
gasification. Simultaneous combustion requires carefully prepared biomass, but is the lowest cost
option. Separate combustion is more commonly employed, but requires additional investment.
Gasification is the highest capital cost choice, but it provides the most flexibility and highest efficiency.
Various utilities have integrated small amounts of biomass into their power generation facilities to
comply with government mandates. An important area of opportunity is in the integration with
agricultural and industrial facilities.
Iowa agriculture generates significant quantities of biomass material, much of which is highly
dispersed. Either gathering large quantities of biomass residue to a large facility or constructing small,
distributed facilities could harness these resources. An important Iowa industry is the livestock sector.
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Manure from livestock operations is suitable for anaerobic digestion systems and can provide heat and
power to farm operations.
Ethanol is a major Iowa export, and Iowa is one of the leading producers of corn ethanol in the
nation. Wet mill corn ethanol refineries generate fiber as part of the corn to ethanol process. This fiber
could be employed in a CHP system, but unfortunately, there are very few wet milling corn plants in
operation. The advent of cellulosic ethanol provides a great opportunity for the development of
integrated CHP units capable of generating enough process heat, and excess power from biofuel
refineries.
Dedicated biomass facilities face important challenges in their ability to scale-‐up. Power plants are
subject to economies of scale that provide strong economic advantages to facilities capable of
converting large quantities of fuel to electricity. The dispersed nature of biomass crops makes it costly to
collect large quantities of feedstock to a centralized location. This has limited dedicated biomass
facilities to small-‐scale operations subject to local biomass availability. Electricity from small-‐scale
facilities is more expensive to produce due to higher capital costs and lower process efficiencies.
Adoption of biomass for power generation provides positive economic impacts to local
communities. For every $1 million spent to purchase feedstock for power generation, local communities
would receive an estimated $7.4 million in income and about 97 jobs would be generated. This revenue
would offset up to $15.5 million from the coal industry, most of which benefits industries outside of
Iowa.
Biomass is a renewable fuel with positive environmental impacts. Conversion of short-‐term rotation
feedstock into energy has net zero emissions over a period of 12 years or less. Replacing fossil fuels in
existing energy facilities helps lower CO2, SOx, and NOx emissions. Optimization of biomass-‐fired facilities
can reduce biomass emissions including particulate matter to negligible quantities. Technology
development could bring significant improvement in the environmental impact of biomass heat and
power generation. Additional research is needed to determine the costs of biomass emission controls.
Government initiatives continue to incentivize the adoption of biomass in existing power plants.
Legislation that seeks to reduce power plant emissions could provide enough economic value to make
biomass an attractive option for facilities seeking to comply with government caps on air pollution.
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Table of Contents
Executive Summary.........................................................................................................................................i
1 Introduction......................................................................................................................................... 1
2 Overview of biomass heat and power applications............................................................................. 2
2.1 Biomass as an energy source.......................................................................................................... 2
2.2 Biomass availability ........................................................................................................................ 4
2.3 The biomass supply chain ............................................................................................................... 6
3 Literature review of biomass heat and power applications .............................................................. 10
3.1 Dedicated biomass heat and power generation........................................................................... 10
3.1.1 Direct combustion.................................................................................................................. 12
3.1.2 Gasification ............................................................................................................................ 14
3.1.3 Anaerobic digestion ............................................................................................................... 16
3.2 Biomass co-‐firing in coal plants .................................................................................................... 18
3.2.1 Simultaneous biomass and coal injection .............................................................................. 19
3.2.2 Separate biomass and coal injection...................................................................................... 20
3.2.3 Biomass gasification combined with coal combustion........................................................... 21
3.3 Biomass integration in agricultural and industrial processing facilities........................................ 22
3.3.1 Iowa agricultural opportunities for biomass CHP .................................................................. 22
3.3.2 Iowa corn ethanol refinery opportunities for biomass CHP................................................... 23
3.4 Power plants with biomass combustion experience .................................................................... 25
4 Economic impacts of co-‐firing biomass for heat and power generation........................................... 28
4.1 Overview of the economics of biomass heat and power generation ........................................... 28
4.2 Economic impacts of biomass heat and power generation.......................................................... 35
5 Environmental impacts of biomass for heat and power generation ................................................. 38
5.1 Overview of the environmental impacts of biomass for heat and power generation ................. 38
5.2 Economic implications of the environmental impacts of biomass co-‐firing for heat and power generation ............................................................................................................................................. 46
5.3 Analysis of emissions from biomass combustion ......................................................................... 48
5.4 Emission control measures for biomass combustion ................................................................... 51
5.5 Handling and applications of ash from biomass combustion ....................................................... 54
6 Conclusions........................................................................................................................................ 57
References .................................................................................................................................................... 1
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
List of Tables
Table 1 Thermal properties of bioenergy and fossil fuels [1] ...................................................................... 3
Table 2 Organic, ultimate, and proximate analysis properties of representative feedstock [1] ................. 4
Table 3 Gasifier producer gas composition [8] .......................................................................................... 15
Table 4 Iowa corn and soybean agricultural crop and residue production [4] .......................................... 22
Table 5 Livestock and poultry manure production rate [14] ..................................................................... 23
Table 6 Location, type of biofuel resources, and biofuel input quantities of biomass power plants
surveyed by NREL [18] ............................................................................................................................... 25
Table 7 Biomass and fossil fuels power technology characterizations employed by the EPA [24] ........... 32
Table 8 Cost of corn stover, coal, and natural gas at the burner (includes drying and grinding costs) [25]
................................................................................................................................................................... 33
Table 9 Comparison of costs and savings for 52.3 MW process heat generation using different feedstock
[25] ............................................................................................................................................................ 34
Table 10 Expenditures in thousands of dollars by IMPLAN Sector per million dollars of gross expenditure
by feedstock type [26] ............................................................................................................................... 36
Table 11 Economic impact for every million $ spent in 2% biomass co-‐firing in southeastern coal power
plants [26].................................................................................................................................................. 37
Table 12 Economic impacts of converting switchgrass to power in Iowa [20] .......................................... 38
Table 13 Greenhouse gas warming potential of biomass and coal co-‐firing for combined heat (52.3 MW)
and power (9.5 MW) [25] .......................................................................................................................... 47
Table 14 Clear Skies Initiative – estimates for 2000 power plant emissions and 2022 projections [26]... 48
Table 15 Range of pollutant values analyzed by the DOE for emission reduction .................................... 48
Table 16 Mean emission levels at 13% O2 from small-‐scale biomass combustion applications [49] ........ 51
Table 17 Comparison of emissions for poor and high standard combustion furnace design [50] ............ 51
Table 18 Comparison of emission and efficiency measurements resulting from the optimization of a
combustion boiler [51] .............................................................................................................................. 53
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
List of Figures
Figure 1 Potential biomass resources available for energy applications as identified in the USDA's 1
billion ton study [3]...................................................................................................................................... 5
Figure 2 Grain combine harvester with stalk-‐gathering head, collecting stalk and leaf in the front wagon
and cob and husk in the rear wagon [6] ...................................................................................................... 9
Figure 3 The biomass supply chain and factors that influence biomass quality (adapted from [7]) ......... 10
Figure 4 Biomass steam generation for heat and power process schematic ............................................ 11
Figure 5 Direct (a) and indirect (b) power generation from flue gas ......................................................... 12
Figure 6 Biomass combustion furnace designs: (a) suspension, (b) grate-‐fired, (c) fluidized bed [5] ....... 14
Figure 7 Biomass Gasification Reactor Designs [8] .................................................................................... 16
Figure 8 Single-‐tank batch feed anaerobic digester [5] ............................................................................. 18
Figure 9 Biomass and coal co-‐firing technologies: a) simultaneous injection, b) separate injection, c)
biomass gasification .................................................................................................................................. 19
Figure 10 Biomass integrated gasification combined cycle diagram for CHP at a corn ethanol facility [17]
................................................................................................................................................................... 24
Figure 11 Simplified description of the kraft mill pulp production process with material flows provided
on a dry-‐basis [21] ..................................................................................................................................... 27
Figure 12 Economies of scale of investment costs for large scale dedicated biomass power generation
plants [23].................................................................................................................................................. 30
Figure 13 Impact of scale on electrical efficiency of biomass power plants [23] ...................................... 31
Figure 14 Annual costs for biomass and coal co-‐firing combined heat (52.3 MW) and power (9.5 MW)
system........................................................................................................................................................ 35
Figure 15 Bioenergy and Fossil Heat and Electricity Energy System Cycles [29] ....................................... 39
Figure 16 Forest Carbon Cycle based on Tonnes of Carbon per Hectare per Year (adapted from [29]) ... 41
Figure 17 Land use change among major sectors in the United States, 1982-‐1997 [31] .......................... 42
Figure 18 World continents' forest change rate (bubble size based on % of world forests in 1990, positive
values indicate forest growth) [36]............................................................................................................ 45
Figure 19 Deforested Land Area in Brazil (1988 -‐ 2008) [38]..................................................................... 46
Figure 20 Bituminous coal, forest residue, and wheat straw chemical fractionation results (adapted from
[48]) ........................................................................................................................................................... 56
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
1 Introduction
The primary goal of this project is to provide a technical analysis of the feasibility and economics of
using biomass to displace coal-‐fired heat and power generation in Iowa with an emphasis on biomass
generation that is economically and environmentally sustainable. This report discusses current biomass
heat and power applications, reviews recent literature and industry reports on relevant biomass
applications, estimates direct and indirect economic benefits of biomass generation, and outlines the
environmental impacts of biomass heat and power generation.
Biomass feedstock is a clean and renewable source of energy that is suitable for combustion
applications. Biomass is currently employed in commercial and industrial applications to generate heat
and power. Direct combustion and co-‐firing in coal plants are some of the most common processes
employed to convert biomass into energy.
There is a growing interest in replacing the use of fossil fuels with clean and renewable sources of
energy. Biomass is a promising source of energy that is suitable for heat and power generation, and it
has been the subject of various studies and reports.
Biomass generation has various direct and indirect economic impacts on local communities. Biomass
heat and power plants provide local jobs and additional sources of revenue to farmers and producers.
There are various governmental incentives in place to help communities and companies increase the
adoption of biomass for energy applications.
There is much debate regarding the environmental impacts of increasing the use of biomass for
energy production. Most studies report positive direct environmental benefits from replacing coal with
biomass in heat and power applications. Indirect environmental benefits are more difficult to measure,
and there is ongoing debate on the indirect environmental impacts of converting biomass to energy.
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2 Overview of biomass heat and power applications
2.1 Biomass as an energy source
Biomass is generally defined as any organic material of recent origin. It includes crops, wood,
municipal waste, and other forms of organic material. Biomass properties are an important
consideration for heat and power applications. Heating value, ultimate and proximate analysis, and
organic composition are commonly employed classifications to compare different types of feedstock.
Heating value is a measure of the amount of heat generated during combustion. Biomass feedstock
has a typical heating value of 18 gigajoules (GJ) per ton. Fossil fuels are dense organic materials with
heating values that are commonly above 20 GJ/t and can exceed 40 GJ/t. Therefore, larger quantities of
biomass are typically required to generate the same amount of energy as a similar amount of fossil fuel.
Table 1 compares the thermal properties of bioenergy feedstocks, liquid biofuels, and fossil fuels.
Ultimate analysis is a description of the elemental composition of biomass. Ultimate analysis
includes carbon, hydrogen, oxygen, nitrogen, sulfur, and ash content. The distribution of these
compounds provides hints as to the combustion behavior of the biomass material. Carbon, hydrogen,
and oxygen affect the energetic performance during combustion, and nitrogen, sulfur, and ash can have
detrimental environmental and operational impacts. Biomass typically contains small amounts of
nitrogen and sulfur. Compared to coal, biomass is an attractive feedstock because of its low sulfur
content. Ash is actually a general term that includes most types of inorganic materials (silica, iron, alkali).
Biomass ash content varies depending on the type of feedstock. Generally, agricultural crops contain
higher ash quantities than woody crops.
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Table 1 Thermal properties of bioenergy and fossil fuels [1]
Heating Value (GJ/t)
Ash (%)
Sulfur (%)
Corn stover 17.6 5.6 Sweet sorghum 15.4 5.5 Sugarcane bagasse 18.1 3.2-‐5.5 0.10-‐0.15 Sugarcane leaves 17.4 7.7 Hardwood 20.5 0.45 0.009 Softwood 19.6 0.3 0.01 Hybrid poplar 19 0.5-‐1.5 0.03 Bamboo 18.5-‐19.4 0.8-‐2.5 0.03-‐0.05 Switchgrass 18.3 4.5-‐5.8 0.12 Miscanthus 17.1-‐19.4 1.5-‐4.5 0.1
Bioenergy Feedstock
Arundo donax 17.1 5-‐6 0.07 Bioethanol 28 <0.01 Liquid Biofuels Biodiesel 40 <0.02 <0.05 Coal (low rank; lignite/sub-‐bituminous) 15-‐19 5-‐20 1.0-‐3.0 Coal (high rank; bituminous/anthracite) 27-‐30 1-‐10 0.5-‐1.5
Fossil Fuels
Oil (typical distillate) 42-‐45 0.5-‐1.5 0.2-‐1.2
Proximate analysis measures fixed carbon, volatile matter, and moisture content. Fixed carbon is the
amount of solid residue left after drying or combustion drives off volatile matter. Moisture content is an
important measure because of its significant impact on combustion performance. Biomass moisture
content can vary from less than 10% by weight to over 50%. Drying is typically required for most
applications to limit energy penalties. A common rule of thumb for calculating drying requirements is
2000 British Thermal Units (BTUs) per pound mass of water evaporated (4.66 MJ/kg). Some heat and
power biomass applications can employ open air-‐drying, which has a low operating costs but could lead
to feedstock degradation. Dedicated drying equipment commonly employs either hot air or steam to
rapidly evaporate moisture [2].
Biomass feedstock is also characterized by its organic composition. Biomass is generally composed
of three macromolecule groups: cellulose, hemicellulose, and lignin. Cellulose consists of long glucose
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
chains and serves as a plant energy repository. Hemicellulose includes five different sugars and
represents 20 to 40% of the biomass weight. Hemicellulose is a long-‐term plant energy store and
structural component. Lignin represents only 10 to 25% of biomass weight but is the main structural
component. Plants develop lignin to protect their cellulose and hemicellulose from the attacks of
biological agents. Table 2 shows biomass properties for corn stover, herbaceous and woody crops.
Table 2 Organic, ultimate and proximate analysis properties of representative feedstock [1]
Feedstock Organic Composition (dry wt-‐%)
Ultimate Analysis (dry wt-‐%)
Proximate Analysis (dry wt-‐%)
Cellulose Hemi-‐cellulose
Lignin Other
C H O N Ash Volatile Matter
Fixed C
Ash
Corn stover 53 15 16 16 44 5.6 43 0.6 6.8 75 19 6 Herbaceous crop
45 30 15 10 47 5.8 42 0.7 4.5 81 15 4
Woody crop 50 23 22 5 48 5.9 44 0.5 1.6 82 16 1.3
2.2 Biomass availability
According to the U.S. Department of Agriculture (USDA), there is more than 1 billion tons of biomass
per year available [3]. The most abundant sources consist of crop residues (corn stover, soybean
residue, etc.) and perennial crops, but various types of woods are also available (Figure 1). Forestlands
can produce about 368 million dry tons of biomass, and 998 million dry tons could be collected from
agricultural lands. These estimates take into account that not all resources are readily accessible due to
lack of transportation infrastructure, environmental concerns, or equipment limitations. Agricultural
resource estimates assume improvements in crop production and collection. These assumptions avoid
direct competition with food, feed, and export demands. There could be additional impacts from
increased agricultural inputs.
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 1 Potential biomass resources available for energy applications as identified in the USDA's 1 billion ton study [3]
Iowa is a leading producer of corn and soybeans and generates large quantities of agricultural
residues. Iowa produced 2.44 billion bushels of corn grain in 2009 and 486 million bushels of soybeans
[4]. Total residue production can be estimated using residue factors that provide a rough estimate of the
weight of residues available from agricultural production. One ton of stover is produced for every ton of
corn grain, and 1.5 tons of soybean residues are generated per ton of soybean. Therefore, annual
estimates for Iowa agricultural residues are approximately 68.3 million tons of stover production per
year and 20.4 million tons of soybean residues. A portion of these residues is required for soil cover to
prevent erosion and may not be available for other uses.
There are few other significant feedstock sources in Iowa to consider for heat and power
generation. For example, biomass grown in Conservation Reserve Program (CRP) land, such as
switchgrass, has been considered a potential source for biomass conversion. The challenge with CRP
grown biomass is in collecting sufficient quantities to serve a nearby biomass facility.
0 50 100 150 200 250 300 350 400 450
Urban wood residues
Fuelwood
Fuel treatments
Loggin & other residue
Wood processing residues
Pulping liquor
Process residues
Grain-‐to-‐ethanol
Perennial crops
Crop residues
QuanWty [million tons/year]
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Some industrial facilities, such as ethanol refineries and pulp and paper mills, can be a significant
source of feedstock. There are two major types of corn ethanol refineries: dry and wet mills. Each of
these generates different types of by-‐products. Dry mills primarily generate distillers dried grains
(DDGS), which have a higher value as feed than fuel. Wet mills produce corn oil, gluten, and fiber by-‐
products, and this fiber is a potential fuel to generate process heat. Most corn ethanol refineries consist
of dry mills with not enough biomass available for conversion to heat and power. Cellulosic ethanol
refineries, such as the Emmetsburg facility, convert corn cobs to ethanol and reject lignin material in the
process. Lignin is structural biomass material that microbes are currently unable to convert into liquid
fuel. Lignin contributes a significant portion of biomass material, and its combustion in cellulosic plants
could provide enough heat and power for the facility and for sale.
Smaller industrial categories to consider in Iowa are pulp and paper mills. Iowa mills generated
181,810 dry tons of unused residues in 2007. Despite being a small contributor to the amount of
biomass available in the state, pulp and paper mills present attractive opportunities for the
development of small-‐scale biomass energy generation.
2.3 The biomass supply chain
Biomass production is a yearlong investment with multiple factors that affect the quality of the final
product. This process can be divided into three stages: growth, harvest, and conversion. The growth and
harvest stages influence the fuel characteristics that are key for biomass conversion to energy.
Iowa soil is one of the most fertile in the world and allows for high productivity of native species.
The proportions of clay, silt, and sand classify soils. Clay consist of particles smaller than 0.002 mm, silt
have sizes between 0.002 and 0.05 mm, and sand particles have sizes of 0.05 to 2 mm. Particles with
sizes greater than 2 mm make it hard to work on soil and limit organic matter retention. [5]
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Sands and sand soils are amenable to treatment at different moisture levels. They are not good at
retaining water, organic matter, or nutrients. They have an advantage with irrigation because salt does
not accumulate. Crop yields in sand soils are lower than other types of soils.
Silty and loamy soils are the best type of soils for agriculture. They have good water retention and
porosity, which allows for aeration. Organic matter and minerals are readily accessible to plants
promoting plant growth. Crop yields are higher in silty soils than other types of soils.
Clay soils are the most difficult to cultivate even at different moisture levels. Clay soils harden at low
moisture levels making it hard to till, and they become plastic at high moisture levels making crumbling
difficult. Clay soils can retain water, but they do so in a way that makes water inaccessible to plants.
Agricultural practices are measures that biomass producers adopt to affect land productivity.
Agricultural practices include soil preparation, which can improve soil properties and increase crop
yields. Conventional, reduced, and no-‐tillage are the three main types of soil treatment in order of
decreasing intensity. Conventional tillage can increase soil erosion, and its practice has decreased in
recent decades. There are a large number of practices that can be considered reduced tillage and their
common feature is less impact on the soil than conventional tillage. No-‐till involves the least amount of
soil treatment but requires heavy use of chemical herbicides [5].
Fertilization, pesticide use, and harvesting date are additional agricultural practices that are
employed throughout the growth stage and before the harvest stage. Fertilization and pesticide use
have increased in recent years, and their purpose is to provide a rich environment for a desired crop
while adversely affecting weeds and bugs. Fertilizer and pesticide use ultimately affect the conversion
process because it can increase the content of undesired energy conversion compounds such as chlorine
and nitrogen.
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Moisture content is an important factor in the choice of harvesting date because it affects biomass
storage. High moisture content promotes degradation by attracting bugs that decompose the material.
Transporting biomass with high moisture content is expensive, and biomass conversion facilities could
charge a penalty for additional drying requirements. On the other hand, harvesting biomass with low
moisture content can become a fire hazard if long-‐term storage is required. Farmers are very adept at
monitoring crop moisture level of conventional crops, and that knowledge should translate to other
types of crops.
Feedstock species is an important factor that impacts final biomass composition as shown in Table 2.
Although corn and soybeans dominate Iowa agriculture, there are a number of native species such as
switchgrass that exhibit high productivity. Different varieties can have slight variations in composition
that can be an important factor for some energy applications. In general, low ash content and high
calorific value are the most desirable attributes for energy applications.
The harvesting stage includes collection and delivery of feedstock to the final conversion facility.
Biomass harvesting is commonly done with harvesting equipment known as a combine, which is capable
of simultaneously collecting crops and separating desired agricultural products from residual material.
Conventional corn grain combines collect corn kernels and discard other parts of the corn plant such as
cob, husk, leaves and stalk. New combine designs capable of collecting corn residues in a single pass
system are being tested. An example of a modified grain combine for residue collection is shown in
Figure 2. These new combines are capable of collecting 64% of the available stover at a productivity rate
of 1.5 hectares per hour [6].
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 2 Grain combine harvester with stalk-‐gathering head, collecting stalk and leaf in the front wagon and cob and husk in the rear wagon [6]
Biomass can follow a number of different pathways after it has been harvested. Farms that are close
enough to a conversion facility would be able to bale their material and transport it to the facility where
it would be purchased on an as-‐needed basis or stored. In some cases, biomass would be transported to
an intermediate location (silo) before being shipped to the conversion facility. This two-‐step process is
known as transshipment. The intermediate location could be employed as more than just an
intermediate storage facility. Silos could include equipment to dry, pelletize, or pre-‐treat the biomass as
appropriate. Silos could be conveniently located next to long-‐range transportation including railroads
and barges enabling feedstock shipment to remote locations.
The conversion stage is the final destination in the biomass supply chain. Figure 3 shows a summary
of the supply chain steps and factors that influence fuel properties. The conversion stage section lists
some key feedstock properties for energy applications.
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 3 The biomass supply chain and factors that influence biomass quality (adapted from [7])
3 Literature review of biomass heat and power applications
3.1 Dedicated biomass heat and power generation
There are three main approaches to the conversion of biomass into heat and power: direct
combustion, gasification, and anaerobic digestion. Direct combustion produces hot gas that can provide
heat to a downstream process; gasification and anaerobic digestion generate a combustible gas (flue
gas) that can be employed directly as a heat source, or combusted for heat and power [5]. The purpose
of these processes is to generate heat or a combustible gas that can be employed directly or indirectly
by raising steam as shown in Figure 4.
Growth • Soil type • Climate • Species • Variety, clone • Age • Harvesmng date • Fermlizamon • Agricultural pracmces • Pesmcides
Harvest • Transport • Harvesmng method • Transshipment • Storage • Drying • Upgrading
Conversion (fuel propermes) • Physical characterismcs • Moisture content • Pollutants • Calorific value • Nutrients • Fungi spores • Slag formamon • Ash content
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 4 Biomass steam generation for heat and power process schematic
Figure 5 shows the two main approaches to converting hot flue gas to electric power. Direct power
generation combusts flue gas in a gas turbine. Blades in the gas turbine rotate as the combustion gases
expand and exit the turbine. It is very important that particles do not enter the gas turbine because they
can damage turbine blades. This is not a concern with natural gas, but can add significant cost to a
biomass power generation system.
Indirect power generation employs a steam turbine to generate power. This design requires high
quality steam, which can be achieved by transferring heat from the combustion of biomass or flue gas.
The benefit of indirect power generation is that it increases the process feedstock flexibility. Although
this option requires additional equipment to generate steam, it can reduce the cost of equipment
related with the consumption of combustion flue gas.
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 5 Direct (a) and indirect (b) power generation from flue gas
3.1.1 Direct combustion
Direct combustion is a four step process that occurs at temperatures that can exceed 2000 °C
depending on the feedstock properties, amount of oxygen available to the reaction, and the furnace
design. The final product is a stream of hot gas that can be used to indirectly raise steam for heat and
power applications.
There are four key steps involved in the combustion process: drying, pyrolysis, flame combustion,
and char combustion. Moisture must be released from the biomass particle before combustion can
proceed. Pyrolysis is a decomposition process that breaks down biomass fibers into volatile gas, organic
compounds, and solid charcoal particles. Drying and pyrolysis are combustion steps that require heat in
order to take place. Pyrolysis products are combustible in the presence of oxygen. Volatile gases are the
first ones to be exposed to the surroundings, and their combustion initiates the flaming combustion
stage. The final step involves the combustion of solid char particles. Although char particles can be fully
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
converted into fuel gas, typical furnace designs are unable to combust 100% of the organic material
present in biomass.
Moisture content absorbs heat from the combustion reaction and reduces the process performance.
Combustion heat raises the temperature of the combustion gases and supports the combustion
reactions. In the presence of high moisture, combustion heat may not be able to sustain the combustion
process, and the generated steam is not typically useful for heat and power applications. Oxygen is the
main driver of the combustion process. There is a theoretical amount of oxygen required to fully
combust the organic material. This amount is known as the stoichiometric oxygen requirement. Direct
combustion systems employ about 20% excess oxygen to prevent incomplete combustion. The furnace
design has a significant impact on how heat is generated and distributed from the combustion chamber.
Figure 6 shows three common biomass furnace designs: suspension, grate-‐fired, and fluidized bed.
Typically, feedstock is introduced into the burner using mechanisms such as a spreader-‐stoker or auger
feeding system along with one or two air streams. Suspension burners employ a rising air stream to
suspend particles as they are combusted. Air is introduced from below a grate, and a secondary stream
can be employed to ensure full particle combustion. This design can achieve efficiencies of up to 99%
with particles of 50 µm diameter or less. Pulverized coal is commonly employed in suspension burners,
which are the most widely used in the U.S. power industry. Grate-‐fired burners are a late nineteenth
century design that consists of a hot rotating grate where biomass is combusted. The fluidized bed
design is the most recent and became commonly used in industry in the 1980s. In a fluidized bed, hot
particles (typically sand) bubble due to the stream of air injected from the bottom of the reactor. The
bubbling motion enables a constant temperature distribution throughout the bed.
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 6 Biomass combustion furnace designs: (a) suspension, (b) grate-‐fired, (c) fluidized bed [5]
Combustion furnaces generate hot flue gas and ash. The flue gas stream provides an indirect source
of heat for a steam or Rankine power cycle. Running water through a heat exchanger that comes into
contact with the flue gas generates steam. A Rankine power cycle consists of an engine that operates by
cycling a fluid through a hot-‐cold cycle that runs a generator. Combustion ash consists mostly of
inorganic compounds such as potassium and sodium. Ash poses equipment maintenance challenges due
to slagging and fouling. Slagging occurs when ash melts and turns into a sticky fluid that can cause
agglomeration in a fluidized bed. Fouling results from ash material coating heat exchanger surfaces,
which adversely affects system performance.
3.1.2 Gasification
Gasification occurs when biomass is heated in the presence of limited oxygen. Typical gasification
temperatures are 800 up to 1200 °C. Limited oxygen prevents pyrolysis volatile gases from further
reacting to form CO2. Gasification converts biomass into producer gas, a combustible mixture of light
15
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
gases that includes: hydrogen, carbon monoxide, carbon dioxide, methane, and nitrogen. If pure oxygen
is employed for biomass combustion, the mixture has a higher heating value and is known as synthetic
gas or syngas. Producer gas can replace natural gas in fuel heating applications. The advantage of
gasification over combustion is that its producer gas is a versatile intermediate feedstock that can be
used for heat, power, chemicals, and liquid fuels. Table 3 shows properties of biomass gasification gas
generated via different reactor configurations. Half the volume of air-‐blown gasification gas consists of
nitrogen, which dilutes the energy content and increases the size requirement for downstream
equipment. Natural gas has an energy value of 38.3 megajoules per cubic meter (MJ/m3). The gas quality
depends on the amount of particulate present in the gas stream. The choice of reactor technology can
be affected by the gas quality required by the process application.
Table 3 Gasifier producer gas composition [8]
Gas composition (%v/v dry)
HHV (MJ/m3)
Gas quality
H2 CO CO2 CH4 N2 Tars Dust Fluid bed air-‐blown 9 14 20 7 50 5.4 Fair Poor Updraft, air-‐blown 11 24 9 3 53 5.5 Poor Good Downdraft, air-‐blown 17 21 13 1 48 5.7 Good Fair Downdraft, oxygen-‐blown 32 48 15 2 3 10.4 Good Good Multi-‐solid fluid bed 15 47 15 23 0 16.1 Fair Poor Twin fluidized bed gasification 31 48 0 21 0 17.4 Fair Poor
Various reactor designs have been proposed for converting biomass to syngas. Figure 7 shows four
common biomass gasification reactor designs. The objective of these reactors is to rapidly heat biomass
while exposed to a limited supply of oxygen. Depending on the design, producer gas and solid residue
(ash) may exit the reactor in the same or separate streams. Downdraft gasification reactors introduce
biomass from the top and oxygen (or air) through the sides. Gasification takes place in the throat
section, and producer gas and solids exit through the bottom. The updraft design introduces oxygen
from the bottom of the reactor with enough velocity to sweep away the producer gas while allowing
16
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
solids to exit through the bottom of the reactor. The bubbling fluid bed and circulating fluid bed are the
most commonly employed reactors due to their simplicity and high conversion efficiency. Fluid bed
reactors are filled with solid particles (typically sand) that are in constant motion due to a stream of air
introduced from the bottom of the reactor. The producer gas and solid particles exit in the gas stream.
Solid-‐gas separation systems, such as the cyclone shown in the circulating fluid bed design, are typically
employed downstream to remove solid particles from the producer gas.
Figure 7 Biomass Gasification Reactor Designs [8]
3.1.3 Anaerobic digestion
Anaerobic digestion is a three-‐step process that takes place at room temperature and atmospheric
pressure. The three steps consist of hydrolysis, acidification, and methanogenesis. The final product is a
methane-‐rich gas suitable for heat generation applications.
During the anaerobic digestion’s first step, organic material undergoes hydrolysis to form simple
organics, acids, and hydrogen and carbon dioxide gas. Coliform bacteria (Escheerichia coli for example)
and pathogens similar to Salmonella drive this first step. The second step is an acidification process that
17
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
produces acetate, hydrogen, and carbon dioxide. Methanogenesis is the final process and results in the
conversion of acids and gases to mostly methane and carbon dioxide (CO2). Anaerobic digestion
generates biogas with 55 to 75% methane by volume, CO2, and small amounts of hydrogen sulfide (H2S).
Yields can be as high as 31, 0.93, and 0.69 cubic meters per kilogram (m3/kg) of volatile solids for
wastewater, human sewage, and distillery waste respectively [9]. Biogas is a suitable replacement for
natural gas once H2S is removed from the gas stream.
Anaerobic digestion takes place in purposely-‐designed tank digesters such as the one illustrated in
Figure 8. Feed can be supplied by batch, intermittent, or continuous feeding. Batch feeding is the least
efficient feed method because it allows microbial activity in the digester to decrease as the feed is
consumed. Intermittent feeding involves feeding and removal of equal amounts of material with loading
rates of 0.5 – 1.5 kilogram (kg) per day and retention times of 2 to 3 months. This method typically
results in incomplete feed conversion since removal rates may not allow sufficient time for gas
conversion. Continuous feeding can achieve the highest rates of conversion. It involves retention times
of 20 days or less and loading rates of 1.6 – 6.4 kg per day. Two-‐stage anaerobic designs have been
employed to reduce the rate-‐limiting impact of methanogenesis.
18
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 8 Single-‐tank batch feed anaerobic digester [5]
Dedicated biomass heat and power systems are limited by the availability of low cost feedstock and
transportation costs. Dedicated biomass systems are well suited for locations where there is significant
availability of organic residue material. Applications that are well suited for dedicated systems are forest
residues, paper and pulp mills, ethanol plants, and large agricultural lots.
Biomass co-‐firing is an attractive pathway to the large-‐scale adoption of biomass for the production
of heat and power. The advantages of biomass co-‐firing in coal plants are that it can employ existing
infrastructure therefore reducing construction costs; it has positive economic impacts on local
communities by generating local revenue and jobs; and it can help meet environmental standards by
reducing direct greenhouse gas emissions.
3.2 Biomass co-firing in coal plants
Co-‐firing is defined as supplementing a primary fuel with a secondary fuel. Biomass can serve as a
supplement for coal combustion and has been successfully employed by various electric utility
companies. There are three major options for biomass co-‐firing in coal plants: simultaneous biomass and
19
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
coal injection, separate biomass and coal injection, and biomass gasification combined with coal
combustion [10].
Figure 9 Biomass and coal co-‐firing technologies: a) simultaneous injection, b) separate injection, c) biomass gasification
3.2.1 Simultaneous biomass and coal injection
This co-‐firing option consists of mixing coal with small quantities of biomass outside of the fuel
boiler. The amount of biomass that can be mixed with coal depends on the type of boiler. Pulverized and
cyclone coal boilers are two common designs considered for biomass co-‐firing. The maximum
percentage of biomass that can be blended with coal is 5% by weight for pulverized coal boilers, and
20% for cyclone coal boilers.
Pulverized coal boilers supply over half of U.S. electricity [11]. These boilers employ coal that has
been crushed to a fine powder. Biomass co-‐firing in pulverized coal boilers requires a mixture of less
than 5% by weight biomass. Feeding biomass with coal increases the power requirement of the
pulverizer, and decreases the feeder speed for ball and race mills. Increasing the biomass fraction would
20
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
cause derating1 of the milling equipment. If biomass co-‐firing affects the milling operation, it is possible
that the rate of feedstock input to the boiler could decrease.
Mixing biomass with coal can cause challenges for coal conversion equipment resulting in limitations
regarding the type of biomass that can be mixed. Bark material can be stringy and difficult to grind in
conventional milling equipment. Straw feedstock can cause plugging in feeding equipment even at blend
fractions of 5% by weight. The plugging occurs because biomass contains more volatile material that
reacts when exposed to the heat enveloping mechanical and reactor equipment. The volatile material
can re-‐condense forming a viscous liquid that acts like glue. Biomass typically has a lower density than
coal. For example, agricultural residues average 50 to 200 kg/m3 while coal density ranges between 600
and 900 kg/m3 [12]. Therefore, a 5% by weight biomass blend represents more than 30% by volume
mixture.
Simultaneous injection requires less investment than other co-‐firing technologies, but is the most
limited option regarding the types and quantities of biomass that can be employed. Cyclone boilers
provide additional flexibility regarding the feed composition, but they are not as common as pulverized
coal boilers. This is particularly true of older coal plants, which were built before cyclone boilers became
a common industrial option.
3.2.2 Separate biomass and coal injection
Separate injection co-‐firing employs pretreatment equipment specifically designed to prepare
biomass before feeding into the boiler. With this approach, biomass is injected at a different section of
the boiler. There are various advantages to this approach: it allows for higher biomass blend levels; it
1 Derating occurs when equipment is employed at lower capacity than it is expected to prevent reductions to
its useful lifetime.
21
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
can help with nitrogen oxide (NOx) reductions; and it can help improve combustion performance when
wet coal is employed.
Higher percentages of biomass can be co-‐fired in coal boilers with separate injection. This is possible
because biomass can be prepared separately and avoid problems associated with using biomass in coal
equipment.
Coal combustion generates significant quantities of NOx compounds, which are potent greenhouse
gases. Biomass increases the amount of nitrogen present in the boiler but also increases the amount of
hydrogen. Coal combustion in the presence of biomass results in a reduction of NOx compounds because
biomass promotes the formation of ammonia (NH3).
The higher moisture content in wet coal reduces the rate of fuel fed into the boiler. Biomass can
therefore serve to increase the amount of combustible fuel available in the reactor. This improves the
utilization of the boiler’s capacity.
Separate biomass and coal injection requires investment in additional equipment to properly
prepare biomass before introducing it into the boiler. Although it provides increased flexibility in the
types of feedstock and quantities that can be employed, it still requires careful control of boiler
performance. Biomass has different combustion performance than coal as discussed in previous
sections. This difference requires that operators monitor the impact of biomass in coal equipment.
3.2.3 Biomass gasification combined with coal combustion
Biomass gasification can be combined with an existing coal power generation plant. Producer gas
from biomass gasification can be fired in a boiler, a designated burner, a gas turbine, or in a waste heat
boiler. Biomass gasification is also attractive for natural gas power facilities. Biomass gasification is
described in detail in section 3.1.2.
22
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Biomass gasification is the most capital-‐intensive co-‐firing option, but provides the most flexibility in
terms of potential applications and feedstock selection. The use of a separate reactor for biomass
combustion allows operators to optimize the performance of the reactor to both fuels.
3.3 Biomass integration in agricultural and industrial processing facilities
Various biomass combined heat and power (CHP) systems have been considered for integration in
industrial and agricultural facilities. Biomass is a by-‐product of various industrial activities and can be
recovered to produce heat or power for the facility or to supply market demand. This chapter discusses
biomass CHP systems suitable for farm operations, corn ethanol refineries, and small-‐scale distributed
heat and power generation systems.
3.3.1 Iowa agricultural opportunities for biomass CHP
Corn and soybean production dominate Iowa’s agricultural landscape and generate significant
quantities of agricultural residue. The USDA employs residue factors to estimate the amount of
agricultural residue generated [13]. In 2009, Iowa produced 2.44 billion bushels of corn grain in 13.7
million acres. In the same year, 9.6 million acres were covered with 486 million bushels of soybeans. The
USDA estimates that for every ton of corn grain there is an equal quantity of residue. For every ton of
soybeans, 1.5 tons of residues are generated. Almost 90 million tons of agricultural residues are
produced in Iowa every year as shown in Table 4.
Table 4 Iowa corn and soybean agricultural crop and residue production [4]
Feedstock Bushels Produced
(millions) Acres Planted (millions)
Residue Factor Tons of Residue
Generated (millions)
Corn 2,440 13.7 1.0 68.3 Soybeans 486 9.6 1.5 20.4 Total 2926 23.3 -‐ 88.7
23
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Livestock and poultry manure are suitable feedstock for anaerobic digestion to produce methane
gas. Production rates for various types of common confinement animals are shown in Table 5.
Anaerobic digesters are relatively inexpensive systems that can convert manure to methane gas, which
can serve as an operation heat source. Methane gas from anaerobic digestion can replace natural gas in
most applications when collected properly as discussed in section 3.1.3.
Table 5 Livestock and poultry manure production rate [14]
Animal Manure Production Rate
(dry kg/head-‐day) Cattle 4.64 Hogs and pigs 0.56 Sheep and lambs 0.76 Chickens 0.025 Commercial broilers 0.040 Turkeys 0.101
3.3.2 Iowa corn ethanol refinery opportunities for biomass CHP
There are more than 40 ethanol refineries in Iowa with total capacity exceeding 3.29 billion gallons
of ethanol per year [15]. The conventional corn ethanol process requires significant quantities of heat
input. A 40 million gallon per year dry grind ethanol plant can consume 537,000 million BTUs (MMBTU)
of heat mostly from the combustion of natural gas [16]. Nevertheless, a recent study estimated that a
corn ethanol facility could meet all its energy demand from the combustion of ethanol co-‐products and
corn cobs [17].
Figure 10 shows the main process units involved in a biomass integrated gasification combined cycle
(BIGCC) at a corn ethanol facility. This design employs a gasifier and a combustor to convert corncobs
and dried syrup to heat and power. Synthetic gas (syngas) from the gasifier is cooled, cleaned, and
compressed before feeding into a gas turbine to generate electricity. The combustor burns corn cobs,
dried syrup, and excess volatile organic compounds (VOC) from the DDGS drying process. Hot
24
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
combustion gases are sent to a heat recovery steam generator (HRSG) to raise process steam required
by the ethanol process. Results indicate that a 50.2 million gallon dry grind corn ethanol plant could
generate 30.4 megawatts of electric power with a net excess of 21.7 MW.
Figure 10 Biomass integrated gasification combined cycle diagram for CHP at a corn ethanol facility [17]
Wet milling corn ethanol plants fell out of favor for a number of reasons despite their ability to
produce higher valued by-‐products than dry mill ethanol plants. In addition to ethanol, wet mills
produce 1.7 lb of corn oil, 3 lb of corn gluten meal (60% protein), 13 lb of corn gluten feed (21% protein)
and 17 lb of CO2 [5]. The high protein content helps increase the marketing value of wet mill by-‐products
and discourages their use for energy generation.
25
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
3.4 Types of power plants with biomass combustion experience
The National Renewable Energy Laboratory (NREL) compiled the experiences of 20 biomass power
plants [18]. Eighteen of these plants were located in the United States, one in Canada, and one in
Finland. Table 6 includes a summary of the information reported by these power plants. Process
residues are the most common form of biofuel employed in these plants, with a significant number
reporting mill residue as their source of fuel. In 2004, up to 41 U.S. power plants were reported to have
experience with biomass co-‐firing [19].
Iowa has experience with biomass power generation. Alliant Energy processed 45 MW of
switchgrass at their Ottumwa power plant. Continuous production at this level would require 274,000
tons of switchgrass per year, generate $16.3 million of industrial output, and provide $6.4 million in
payments to workers, farmers, and investors [20]. Unfortunately, the Ottumwa plant did not continue to
process biomass after the initial project was completed.
Table 6 Location, type of biofuel resources, and biofuel input quantities of biomass power plants surveyed by NREL [18]
Plant Location Biofuel Resources (Residues) Tons/year MWe Williams Lake British Columbia Mill 768,000 60 Okeelanta (cogen) Florida Bagasse, urban 694,000 74 Shasta California Mill, forest, ag 846,000 49.9 Colmac California Urban, ag, coke 573,000 49 Stratton Maine Mill, forest 561,000 45 Kettle Falls Washington Mill 542,000 46 Snohomish (cogen) Washington Mill, urban 410,000 39 Ridge Florida Urban, tires, landfill gas fuel (LFG) 376,000 40 Grayling Michigan Mill, forest 320,000 36 Bay Front Wisconsin Mill, Tire-‐derived fuel (TDF), coal 251,000 30 McNeil Vermont Forest, mill, urban 255,000 50 Lahti (cogen)* Finland Urban, refuse-‐derived fuel (RDF) 252,000 25 Multitrade Virginia Mill 219,000 79.5 Madera California Ag, forest, mill 308,000 25 Tracy California Ag, urban 214,000 18.5 Camas (cogen) Washington Mill 194,000 17 Tacoma Washington Wood, RDF, coal 221,000 40 Greenidge** New York Manufacturing 98,000 10.8 Chowchilla II California Ag, forest, mill 125,000 10
26
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
El Nido California Ag, forest, mill 125,000 10 * 167 total net MW, 15% from biofuels and 85% from coal ** 108 total net MW, 10% from wood and 90% from coal
The pulp and paper mill industry requires large quantities of energy and has gained a lot of
experience in the use of their biomass process residues. The most common paper plant process in the
U.S. is the kraft pulping process. In the typical kraft mill, wood logs are initially debarked and chipped
yielding about 91% of the biomass input in wood chips and the rest in waste wood known as “hog fuel.”
The wood chips are then processed by wood digestors wherein cellulose is separated using a sodium
sulfide and sodium hydroxide solution (“white liquor”). Washing of the treated wood chips generates a
dark liquid known as “black liquor,” which contains chemicals, lignin, and hemicellulose. The facility can
send cellulose to be processed into a pulp product or paper depending on the availability of a paper mill.
Black liquor contains around half the energy of the wood chips. To harness this energy, the black liquor
is initially dried to almost 80% solids content and then sent to a boiler to generate steam. Steam from
the black liquor recovery boiler is sent, along with steam generated from burning hog fuel, to a steam
turbine for power generation. Kraft mills do not generate enough process heat for the pulp production
process and must purchase a fraction of their electricity needs from the grid. Figure 11 shows a
summary diagram of the kraft mill process. A detailed report of opportunities for biomass fuels in the
pulp and paper industry can be found in the publication by Larson et al. [21]. The pulp and paper mill
industry is not widely prevalent in Iowa and does not present a major opportunity for biomass to energy
within the state.
27
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 11 Simplified description of the kraft mill pulp production process with material flows provided on a dry-‐basis [21]
Process residues present an economic and environmental opportunity for biofuel plants. Residues
from forest and milling operations can be often found at zero to negative cost. Generators of biofuel
residues need to dispose of this material, which sometimes ends up in landfills at a cost. Forest residue
may be left exposed to the elements where it decomposes before finally being disposed or burnt for
28
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
heat. These residues emit greenhouse gases as they decompose or following incineration and power
generation is a responsible way of accounting for these emissions.
4 Economic impacts of co-firing biomass for heat and power generation
4.1 Overview of the economics of biomass heat and power generation
The economic impacts of employing biomass for heat and power generation are strongly dependant
on scale. Capital costs and process efficiencies become more attractive at medium (50 megawatts
(MW)) to large-‐scale (>250 MW) facilities, but biomass availability typically limits the capacity of
dedicated biomass heat and power plants. Biomass co-‐firing in existing coal plants requires a smaller
investment than a dedicated biomass facility, but biomass utilization in these facilities is strongly
dependent on the cost of coal.
The cost of generating power typically decreases with increasing facility capacity. This relationship
follows a power law (Equation 1) that is commonly known as economies of scale [22]. The dominant
costs that impact economies of scale are capital costs. As plant capacity increases, capital costs per unit
of power generated decrease by a scale factor of ‘n’, which varies between 0.6 and 1. The implication is
that large power facilities can generate power at a lower cost than smaller facilities. This is particularly
true of coal generation plants, but biomass-‐fired plants are at a disadvantage because of diseconomies
of scale.
Equation 1 Economies of scale power law (C – capital cost; M – capacity (tons per day), n – scale factor)
Diseconomies of scale are product costs that increase with capacity. Biomass delivery costs typically
increase with demand because of biomass collection costs. Coal can be transported from a single point
29
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
(the mouth of the coal mine) to a power plant, and higher coal demand can be met by increasing the
frequency of deliveries from the coal mine. Biomass on the other hand, must be collected over a large
area to satisfy increased demand. Diseconomies of scale follow the same power law described in
Equation 1 with a scale factor greater than 1. For a biomass power plant, delivery costs have a scale
factor of about 1.5.
Figure 12 shows the economies of scale relationship for the investment costs of dedicated biomass-‐
fired heat and power plants. Specific investment is the ratio of investment cost to plant capacity. Power
plants with capacities of less than 50 MW have specific investment costs that can be higher than $1500
per kilowatt (kW). Biomass power plants with capacities greater than 250 MW have costs of about $500
per kW. Investment costs also depend on the choice of combustion technology. Grate firing with steam
turbine technology are the lowest cost option, and biomass integrated gasification combined cycles
(BIGCC) are the most expensive. Expensive biomass heat and power systems are attractive to power
utilities because they offer higher efficiencies.
30
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 12 Economies of scale of investment costs for large scale dedicated biomass power generation plants [23]
Power generation efficiency increases with plant capacity. Larger facilities are capable of operating
at a wider range of conditions and therefore have more flexibility to optimize their systems. Figure 13
shows the range of electrical efficiency for biomass to power facilities. BIGCC have biomass to power
efficiencies that exceed 45%. Even at plant capacities of less than 50 MW, BIGCC systems can achieve
efficiencies higher than 40%. Unfortunately, capital costs for BIGCC systems are prohibitive at small
scale. Fluidized bed combustion with steam turbine systems can achieve power efficiencies of over 30%
at significantly lower cost than BIGCC. The choice of biomass heat and power technology requires
careful consideration of the impact of scale on capital cost and operating efficiency.
31
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 13 Impact of scale on electrical efficiency of biomass power plants [23]
Biomass availability and delivery costs can significantly limit the ability to scale a biomass conversion
facility. The relationship between the cost of collecting biomass and the facility capacity is shown in
Equation 2. This equation assumes that a circular region where biomass is grown and collected
surrounds a biomass facility. ‘M’ is the amount of feedstock per year sent to the facility. ‘Y’ is the yield of
feedstock in the region, which depends on the type of feedstock and soil productivity. The factor ‘f’
represents the fraction of land that supplies feedstock to the facility. It is recommended for Iowa that ‘f’
have a value of 60% or less for sustainable collection of agricultural residues. Tortuosity ‘τ’ accounts for
actual travel distances which differ from the straight-‐line distance between two locations. Finally, ‘T’ is
the freight transport cost per ton-‐mile that biomass has to travel. The implication of this relationship is
that feedstock costs, and subsequently a portion of power costs, increase with the capacity of a biomass
plant.
32
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Equation 2 Average biomass delivery costs (D) as a function of transportation cost (T), tortuosity (τ), feedstock input (M), biomass yield (Y), and sustainability factor (f)
The National Renewable Energy Laboratory (NREL) summarized the technology characterizations
employed by the Environmental Protection Agency (EPA), and are shown in Table 7. Heat rate is a ratio
of the energy present in the feedstock to the power generated by the system, and it is an alternative
measure to efficiency. Fixed costs such as financial charges, capital charges, and labor costs contribute a
majority of the annual expenditures of power plants. Industrial turbines include technologies that have
historically dominated the power generation industry, and advanced turbine systems include concept
designs that may not be in operation in the U.S. The costs shown in Table 7 are representative of mature
process designs and do not accurately reflect the costs of building and operating a new biorefinery
plant.
Table 7 Biomass and fossil fuels power technology characterizations employed by the EPA [24]
Component Industrial turbine Advanced turbine systems Biomass Coal Biomass Coal Natural Gas ‘Low’ technology specifications Heat Rate (Btu/kWh)
8660 8700 7579 7614 6202
Efficiency (% HHV) 39.4 39.2 45.0 44.8 55.0 Fixed O + M ($/kW) 51.25 51.25 39.66 39.66 28.80 Variable O + M (million $/kWh)
3.15 3.15 2.46 2.46 0.712
Total Capital ($/kW) 1230 1254 1023 1047 522.50 ‘High’ technology specifications Heat Rate (Btu/kWh)
9400 8700 8227 7614 6202
Efficiency (% HHV) 36.3 39.2 41.5 44.8 55.0 Fixed O + M ($/kW) 44.71 36.44 34.60 28.20 28.80 Variable O + M (million $/kWh)
3.65 2.60 2.85 2.03 0.712
Total Capital ($/kW) 1488 1254 1243 1047 522.50
33
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Researchers from Oak Ridge National Laboratory (ORNL) published a recent techno-‐economic
analysis of corn stover CHP to supply a corn ethanol facility [25]. Their study compared corn stover to
coal and natural gas and developed scenarios for supplying heat and power with combinations of
biomass and coal. Table 8 shows the costs of the various energy feedstocks considered in the study.
Costs are provided as fuel cost at the burner because pretreatment can significantly increase feedstock
cost depending on feedstock properties and process requirements.
Table 8 Cost of corn stover, coal, and natural gas at the burner (includes drying and grinding costs) [25]
Corn stover Coal Natural gas Bale Chop Pellet Fuel cost at the burner ($/Mg)
$73 $84 $86 $54 $424
Higher heating value (MJ/kg)
16.5 16.5 16.5 28 53
Energy cost at the burner ($/MJ)
$4.4 $5.1 $5.2 $1.9 $8
Results for process heat generation are shown in Table 9. Coal and natural gas systems employ less
feedstock material because of higher process efficiencies. The total investment costs were estimated to
be the same for biomass and coal systems. Coal burners were estimated to be half the cost of biomass
burners, but coal facilities require expensive gas clean-‐up systems particularly for sulfur collection. Coal
was found to have the lowest annual cost followed by the corn stover design. Annual savings represent
the costs avoided by the ethanol facility in which these systems are incorporated. Based on their
assumptions for natural gas prices and system design, natural gas would not provide net annual savings.
Corn stover and coal total investment costs shown in this table are identical based on the assumption
that similar equipment could be employed to convert either feedstock.
34
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Table 9 Comparison of costs and savings for 52.3 MW process heat generation using different feedstock [25]
Corn stover Coal Natural gas
Bale Chop Pellet Annual fuel consumption (billion gm) 121.27 121.27 121.27 73.63 56.61 Total investment cost (million $) 18.89 18.89 18.89 18.89 8.62 Annual O&M cost (million $) 3.24 3.24 3.24 3.24 2.02 Annual fuel cost (million $) 8.81 10.22 9.69 3.98 15.52 Annual ash disposal cost (million $) 0.14 0.14 0.14 0.16 – Total annual cost (million $) 12.19 13.50 13.07 7.37 17.54 Total annual savings (million $) 3.59 1.94 2.56 9.18 – Benefit-‐Cost ratio 7.57 4.55 5.69 17.55 –
ORNL’s techno-‐economic study also evaluated the costs of co-‐firing varying proportions of corn
stover and coal. They investigated 100, 75, 50, 25, and 0% biomass and coal mixtures. The results of
their analysis are shown in Figure 14. Total costs increase and savings decrease, with higher biomass
fractions due to the higher cost of biomass compared to coal. As shown in the figure, fuel costs
contribute significantly to the increase in total costs. Ash disposal costs increase from $0.16 to $0.18
million with lower biomass fraction. Although these costs were estimated for a CHP system at a corn
ethanol plant, they do not consider the combustion of any corn ethanol by-‐products such as cobs or
DDGS. The total investment cost for this biomass and coal co-‐firing system generating 52.3 MW of heat
and 9.5 MW of electricity was estimated at $38 million. The payback period was calculated to be 6 years.
35
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 14 Annual costs for biomass and coal co-‐firing combined heat (52.3 MW) and power (9.5 MW) system
4.2 Economic impacts of biomass heat and power generation
Direct economic impacts consist of monetary benefits or costs, and jobs generated by a given
activity. Impacts are considered direct when they are the immediate result of an activity. For example:
income from the sale of a crop. Direct economic impacts are relatively easy to calculate and are the first
step in calculating indirect economic impacts.
Indirect economic impacts are benefits or costs, and jobs that result from the direct economic
impact of a given activity. For example, if a farmer purchases fertilizer, their activity would indirectly
provide income and jobs to the fertilizer industry. Indirect economic impacts are difficult to estimate.
Economists employ specialized tools to provide reasonable estimates to community advisors. Direct and
indirect economic impacts are very important to community planners because they are ideal tools for
deciding whether to support a given commercial activity within a community.
English et al. conducted a recent study on the economic impacts of co-‐firing biomass with coal in
power plants in the southeastern U.S. [26]. Their study employed IMPLANTM software to develop their
$-‐
$2
$4
$6
$8
$10
$12
$14
$16
$18
100 75 50 25 0
Ann
ual Cost (million $)
Biomass FracWon (%)
O&M cost Fuel cost Ash disposal cost Total cost Total savings
36
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
economic models. IMPLANTM collects annual industry information for county, state, and national level
economic models. An example of this data is shown in Table 10, which includes the proprietary income
in thousands of dollars generated for every million dollars spent in the purchase of biomass feedstock.
This study is not entirely applicable to Iowa where different agricultural practices and growing
conditions can significantly alter assumptions for agricultural inputs.
Table 10 Expenditures in thousands of dollars by IMPLAN Sector per million dollars of gross expenditure by feedstock type [26]
IMPLAN Sector
Description Agricultural Residues
Forest Residues
Switchgrass Poplar Mill Urban Waste
20 Seeds 0 0 30 100 0 0 26 Miscellaneous 160 90 40 50 0 0 26 Operating Costs 0 0 20 100 0 0 202 Fertilizer 0 0 310 40 0 0 204 Chemicals 0 0 10 110 0 0 451 Fuel/Lube 70 60 80 40 360 310 456 Depreciation 240 280 220 110 140 180 456 Capital 70 60 10 30 10 10 460 Insurance 0 10 20 10 10 10 482 Repair 330 170 110 110 130 160 Labor 130 330 150 300 350 330
The study by English et al. [26] found that replacing 355,400 tons of coal with a 2% biomass co-‐fire
fraction would decrease coal expenditure by $12.5 million. The biomass feedstock sector would gain
$10.3 million per year with proprietors earning $1.3 million. When the decrease in coal expenditure is
taken into account, the southeastern region was expected to gain a direct economic activity increase of
$5.5 million and nearly 100 additional jobs. The direct and indirect economic impacts total $7.4 million
with an initial impact of $7.5 million to construct biomass co-‐firing facilities.
Table 11 includes a breakdown of the main sectors affected by replacing 2% of coal with biomass for
power generation. The transportation sector includes all freight operations for coal and biomass
transport. Direct operating income consists of labor income at the power plant; income in the bio-‐based
37
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
feedstock sector would benefit biomass producers. The coal sector would experience a decrease in
income and jobs due to the reduced demand for coal. If these results were applied to Iowa, a decrease
in coal expenditure would not affect the state negatively because Iowa is a net importer of coal.
Table 11 Economic impact for every million $ spent in 2% biomass co-‐firing in southeastern coal power plants [26]
Income (1000 $) Jobs
Sector Direct Total Direct Total Transportation $1,455 $2,995 14.3 34.9 Operating $704 $1,011 3.6 8.0 Coal Replacement -‐$8,368 -‐$15,512 -‐34.4 -‐126.9 Bio-‐based Feedstock $11,663 $18,854 79.8 180.8
Total Annual Investment (Non-‐annual) $5,453 $7,349 63.3 96.8 There is very scarce information on direct and indirect economic impacts of biomass co-‐firing in
Iowa. Direct and indirect economic impact studies are typically conducted for a specific community,
county, state, or nation. Therefore, it is difficult to apply results from a study to a different region or
technology.
The most recent and relevant study on economic impact of biomass for power generation was
conducted in 2002 by the Iowa Policy Project [20]. This study considered the impact of switchgrass for
energy generation. The data was based on the operation of the Alliant Energy power plant near
Ottumwa, Iowa, which burned switchgrass to generate electricity. The plant had a 45 MW biomass
capacity, and was estimated to produce $16.3 million in revenue to farmers with income of $6.4 million
from the sale of 274,000 tons of switchgrass. According to the study, this plant would directly create 331
jobs, or 470 total jobs from the conversion of switchgrass to energy. A summary of these results is
shown in Table 12.
38
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Table 12 Economic impacts of converting switchgrass to power in Iowa [20]
Direct Indirect Induced Total
Total Industrial Output (sales) $16,282,000 $6,609,000 $3,729,000 $26,620,000 Labor Income $4,396,000 $1,999,000 $1,394,000 $7,788,000 Value Added (inc. labor income) $6,378,000 $3,573,000 $2,350,000 $12,301,000 Jobs 331 77 62 470
5 Environmental impacts of biomass for heat and power generation
5.1 Overview of the environmental impacts of biomass for heat and power generation
There is much concern about the environmental impacts of generating energy from fossil fuels.
Biomass has been envisioned as an option to reduce greenhouse gas emissions, but there is debate on
its life cycle potential for greenhouse gas emission reduction. Direct emissions from biomass are widely
considered to be net-‐zero emissions, but there is not a consensus on indirect emissions.
Fossil fuels consist of hydrocarbons that have been sequestered over millennia by natural processes
that permanently reduced the amount of CO2 in the atmosphere. The widespread use of coal,
petroleum, and natural gas for energy generation releases these permanently sequestered
hydrocarbons to the atmosphere. According to the Energy Information Administration, 5,955 million
metric tons of carbon dioxide was emitted in 2007 by the United States alone [27]. Figure 15 shows a
comparison of bioenergy and fossil heat and electricity energy system cycles. Fossil energy systems do
not have any mechanisms for reducing atmospheric carbon whereas biomass acts as a carbon sink with
potential for long-‐term sequestration. A sustainable bioenergy carbon cycle employs short-‐rotation
crops that allow for short carbon payback periods. Kim and Dale estimated that a E85 fuel system would
have a payback period of 31 years with forest conversion or 12 years with grassland [28].
39
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 15 Bioenergy and Fossil Heat and Electricity Energy System Cycles [29]
40
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Biomass combustion also emits CO2 into the atmosphere, but unlike fossil fuels, these emissions are
considered to be net-‐zero emissions of greenhouse gas emissions. Carbon dioxide from the atmosphere
is absorbed during the plant growth phase, and combustion of plant matter emits an equivalent amount
of CO2 into the atmosphere resulting in a near net-‐zero carbon cycle. In fact, forest restoration has been
considered as a means to reduce atmospheric CO2 concentrations [30]. Figure 16 shows a forest carbon
cycle schematic. The figure shows that an estimated 14 tonnes of carbon per hectare per year are
removed by forests from the atmosphere via photosynthesis. Forests remove about 4 tonnes of carbon
per hectare per year, and possibly more depending on the net increase in soil carbon from foliage,
seeds, woods, and understorey that remains underground.
41
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 16 Forest Carbon Cycle based on Tonnes of Carbon per Hectare per Year (adapted from [29])
On the other hand, combustion of long-‐term rotation feedstock is considered to have positive net
greenhouse gas emissions. Long-‐term rotation biomass, such as forests, sequesters atmospheric carbon
for periods of hundreds or thousands of years. Combustion of these resources results in a sudden, step-‐
increase in the concentration of atmospheric CO2.
There is an important distinction between direct and indirect greenhouse gas emissions. Direct
emissions are emissions that result from the processes that convert biomass into energy. Indirect
42
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
emissions result from external activities that the energy producer requires but does not control. For
example, CO2 leaving a power plant’s stack constitutes a direct emission. Emissions from the diesel
engines of trains carrying coal to the power plant are considered indirect emissions for the power
facility. Classification of indirect emissions can be difficult because of how industrial processes relate to
each other. Indirect emissions resulting from land use change are of particular interest and debate to
the biomass energy industry.
The impacts of land use change on global emissions have generated interest among researchers and
regulators. Within the U.S., land use change commonly occurs among urban, forest, crop, pasture, and
range sectors. Figure 17 shows how land use has been exchanged among these sectors between 1982
and 1997. The largest change in land use over this period has been the conversion of pasture and range
to forest with 17.1 million acres. A significant portion (10.3 million acres) of forestland has been
overtaken by the expansion of urban areas [31].
Figure 17 Land use change among major sectors in the United States, 1982-‐1997 [31]
43
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Examples of direct environmental impacts resulting from land use change include when a farmer
chooses to clear trees to provide pasture, or when marginal land is brought into production. Direct
environmental impacts are easier to quantify and therefore amenable to public policy. The American
Clean Energy and Security Act (ACES) introduced in 2009 seeks to incentivize practices that lead to
reduced greenhouse gas emissions [32]. The challenge for carbon legislators is to properly account for
indirect environmental impacts.
A commonly cited example of indirect land use change is the notion that employing food crops for
energy would encourage the clearing of forestland in developing countries to meet food shortages.
Searchinger et al. published a paper that explored the impact of indirect land use change in the context
of the corn ethanol industry [33]. This study employed the FAPRI [34] model to estimate the global
impacts of converting corn to ethanol. Their results indicate that life cycle emissions of corn ethanol
increase from 74 to 177 grams of CO2 equivalent per MJ of fuel when land use change impacts are
included. Emissions from gasoline consumption are estimated to be 92 grams of CO2 equivalent per MJ
of fuel. Therefore, corn ethanol emissions go from a net reduction over gasoline to a net increase when
indirect land use impacts are taken into account.
The indirect land use change (ILUC) model employed by Searchinger et al. includes a number of
debatable assumptions that have been analyzed by Mathews and Tan [35]. Searchinger et al. attributes
that ILUC would be caused by a spike in U.S. corn-‐based ethanol and ignores that:
a. There are other ways to meet ethanol (and biofuel) demand than with corn ethanol;
b. Ethanol demand could be met from foreign sources without requiring the diversion of more
U.S. corn to ethanol;
44
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
c. The calculations employ trends from the 1990s to project impacts in 2016. Data from the
1990s is skewed due to the rapid industrial growth of India and China at the time and
complete lack of regulatory control;
d. Biomass yields continue to improve both in the U.S. and around the world; and
e. The U.S. could enact regulatory measures to counter the impact of ILUC without necessarily
reducing biofuel development.
Consideration of any of these assumptions could significantly alter the environmental profile of corn
ethanol. Meeting future ethanol demand with cellulosic feedstock would limit competition with food
crops and prevent developing-‐world farmers from clearing additional land for food. U.S. ethanol
demand could be met with foreign sources of ethanol that do not have a major ILUC impact.
High deforestation rates predate the growth of the ethanol industry. In fact, deforestation rates
have decreased from -‐0.22% to -‐0.18 percent from the 90’s to the first half of this decade (2000 to
2005). Asia shows the greatest reversal with a deforestation rate of 0.14% between 1990 and 2000, and
a forest growth rate of 0.18% from 2000 to 2005 [36]. Figure 18 shows forestland change rates for
different world regions.
45
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 18 World continents' forest change rate (bubble size based on % of world forests in 1990, positive values indicate forest growth) [36]
A region with significant deforestation in the past two decades is South America, where rapid
economic growth has resulted in increasing rates of deforestation. Since 1988, Brazil has seen two
marked peaks in deforestation (1995 and 2004) when 11,220 square miles (mi2) and 10,588 mi2 of
forests were cut. The 2004 peak was followed by a drop to less than 4,500 mi2 of deforested land in
2007 as shown in Figure 19. The major cause of deforestation is attributed to cattle ranching with 65 to
70% of forest clearing between 2000 and 2005 followed by an increase of small-‐scale agriculture
between 20 and 25% [37]. Various economical factors contribute to forest clearing for cattle ranching
such as currency devaluation, increased meat consumption in Brazil and other countries, and
infrastructure improvements that allow access to Amazonian forests.
1; -‐0.64%
2; -‐0.14%
3; 0.09%
North and Central America, -‐0.05% 5; -‐0.21%
6; -‐0.44%
1; -‐0.62%
2; 0.18%
3; 0.07%
North and Central America, -‐0.05%
5; -‐0.17%
6; -‐0.50%
-‐0.80%
-‐0.60%
-‐0.40%
-‐0.20%
0.00%
0.20%
0.40%
Forest Lan
d Ch
ange Rate
1990 -‐ 2000 2000 -‐ 2005
46
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 19 Deforested Land Area in Brazil (1988 -‐ 2008) [38]
The study of indirect land use change impacts is currently in its infancy. Indirect land use changes
are recognized to have significant impact on global greenhouse gas emissions: it is estimated that land
use change caused by a variety of human activities has contributed one third of anthropogenic
emissions (and one fifth of all emissions in the 90s) since 1750 [39, 40]. Unfortunately, the mechanisms
behind land use change are not well understood and have only recently generated much scientific
interest [41]. There are numerous variables that can impact the market forces that cause indirect land
use change. The choice of variables and assumptions to consider can significantly alter life cycle analysis
results [28]. Considering the recent history of deforestation rates, particularly in Brazil, it is difficult to
find a direct link between the growing demand for biofuels and global land changes.
5.2 Economic implications of the environmental impacts of biomass co-firing for heat and power generation
Carbon dioxide, sulfur dioxide (SO2), and methane (C2H4) gas are some of the compounds emitted
from coal combustion with the highest greenhouse gas warming potential. Greenhouse gas warming
0
2,000
4,000
6,000
8,000
10,000
12,000
1985 1990 1995 2000 2005 2010
Deforested Land
(Squ
are Miles)
47
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
potential is measured in units of CO2 equivalent. A carbon mass of 12 kg has an equivalent CO2 mass of
44 kg.
As shown in Table 13, biomass co-‐firing can significantly reduce emissions of these compounds in
coal plants. A coal-‐fired power plant emits about 3.29 Mg of CO2 equivalent CO2, 47.2 kg of CO2
equivalent SO2, and 0.02 g of C2H4 per Mg of CO2. Replacing 100% of coal with biomass in the same plant
would lower emissions to 5.65 kg of SO2 per Mg of biomass, and negligible quantities of CO2 and C2H4.
Table 13 Greenhouse gas warming potential of biomass and coal co-‐firing for combined heat (52.3 MW) and power (9.5 MW) [25]
Biomass fraction (%) 0 25 50 75 100
CO2 eq. per Mg of fuel (Mg/Mg)
3.29 2.16 1.31 0.64 0.1
SO2 eq. per Mg of fuel (kg/Mg)
47.23 32.49 21.36 12.65 5.65
C2H4 eq. per Mg of fuel (g/Mg)
0.02 0.02 0.03 0.02 0.02
Carbon legislation could provide attractive incentives to energy producers to lower their carbon
emissions. The Clear Skies Initiative enacted in 2002 proposed to cap SO2, NOx, and mercury emissions
from power plants between now and 2022. The 2000 estimates and 2022 projections are shown in Table
14. The Clear Skies Initiative calls for 67%, 63%, and 73% reductions in SO2, NOx, and mercury emissions
throughout the United States between 2000 and 2022. The papers included in this report indicate that
biomass is a viable option for emission reduction when done economically.
48
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Table 14 Clear Skies Initiative – estimates for 2000 power plant emissions and 2022 projections [26]
SO2
(1000 tons) NOx
(1000 tons) Mercury (tons)
State/Region 2000 2022 2000 2022 2000 2022 Alabama 500 75 182 31 2.53 0.38 Georgia 508 66 185 37 1.47 0.25 Kentucky 588 194 244 44 1.78 0.32 Mississippi 129 9 65 11 0.24 0.04 North Carolina 459 133 161 45 1.52 0.67 South Carolina 200 64 87 26 0.53 0.19 Tennessee 425 119 156 39 1.12 0.38 Virginia 213 81 82 32 0.64 0.3 Regional Total 3,021 741 1,162 265 9.82 2.53
United States 11,818 3,900 4,595 1,700 67 18
The Department of Energy (DOE) considered various economic incentives for emission control
strategies [42]. The range of values considered in the DOE report is shown in Table 15. NOx is particularly
harmful because of its impact to both the environment and human health. NOx is known for causing
smog and a number of respiratory illnesses.
Table 15 Range of pollutant values analyzed by the DOE for emission reduction
Costs in $/ton Carbon NOx SOx
Base 0 0 142 Low Carbon 70 2,374 142 High Carbon 120 2,374 142
Carbon legislation is likely to help make biomass an economically attractive fuel for existing coal
power plants. As discussed in previous sections, biomass combustion results in lower emissions
compared to coal whether it is employed as the only source of fuel or in a co-‐firing scenario.
5.3 Analysis of emissions from biomass combustion
Emissions from biomass combustion can be classified into three separate groups: emissions from
complete combustion, emissions from incomplete combustion, and particle emissions. The relative
49
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
importance of these groups will depend on the application scale, facility operation, and feedstock
properties.
Large-‐scale combustion facilities typically include emission control equipment and can achieve
almost complete combustion. Small-‐ and medium-‐scale facilities may not include the necessary
equipment to contain certain pollutants or to achieve full combustion. Small-‐scale units such as
domestic stoves can pose a challenge in dealing with some types of pollutants. Medium-‐scale facilities
could face economic challenges to adopt measures that limit pollutant emissions. Feedstock availability
can also be an important constraint for small-‐ and medium-‐scale operations.
Emissions from complete combustion include CO2, NOx, N2O, SOx, and hydrochloric acid (HCl). As
discussed previously, the quantities of most of these pollutants are lower than from coal combustion.
HCl can be found in significant concentrations in herbaceous feedstock such as miscanthus, grass, and
straw, but is less of a concern for woody biomass. During combustion, most of the HCl forms salts, KCl
and NaCl, and trace amounts are emitted as dioxins and organic chlorine. Feedstock washing is an
effective means to reduce HCl emissions, and additional measures can be taken in the combustion
equipment [43-‐45].
Emissions from incomplete combustion include carbon monoxide, methane, Non-‐Methane Volatile
Organic Compounds (NMVOC), Polycyclic Aromatic Hydrocarbons (PAH), Polychlorinated Dioxins and
Furans (PCDD/PCDF), Ammonia, and ground-‐level Ozone (O3). Incomplete combustion can occur
because of inadequate air and fuel mixing in the combustion chamber, low combustion temperatures, or
short residence times.
50
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
PAH is a group of compounds known to have carcinogenic effects. PAH formation is an intermediate
step of the conversion of fuel carbon to CO2 and hydrogen to H2O. PAH emissions were found to peak at
temperatures between 600 and 800 °C and rapidly decrease at higher temperatures [46].
Formation of PCDD/PCDF occurs at temperatures between 180 and 500 °C due to complex
interactions between carbon, chlorine, catalysts, and oxygen. The high alkali content of herbaceous
biomass reduces the formation of PCDD/PCDF by promoting salt compounds. Emissions of PCDD/PCDF
are typically below the health risk limit and can be reduced by various control measures [45, 47].
Ground-‐level O3 formation takes place during photochemical atmospheric reactions involving CO,
CH4, NMVOC, and NOx. O3 emissions can be reduced indirectly by limiting incomplete combustion
emissions [48].
Particle emissions include fly-‐ash, soot, char, and tar. Fly-‐ash consists of coarse particles (diameter >
1 µm) and aerosols (diameter < 1 µm). Coarse particles consist of ash material that becomes entrained
with the flue gases, and aerosols are solid compounds formed during combustion. Soot consists mostly
of carbon and forms when there is a lack of local oxygen. Combustion char includes organic compounds
and alkali material, and can become entrained in the flue gas. Tar is a dark, viscous liquid that consists of
condensed heavy hydrocarbons and can contribute most of the particle emissions in small-‐scale
combustion applications [48]. Table 16 includes measured arithmetic mean emissions from biomass
combustion in various types of small-‐scale applications.
51
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Table 16 Mean emission levels at 13% O2 from small-‐scale biomass combustion applications [49]
Load [kW]
Excess air ratio
CO [mg/m3]
CxHy [mg/m3]
Particles [mg/m3]
NOx [mg/m3]
Temp [°C]
Efficiency [%]
Wood Stoves 9.33 2.43 4986 581 130 118 307 70 Fireplace inserts 14.07 2.87 3326 373 50 118 283 74 Heat-‐storing stoves
13.31 2.53 2756 264 54 147 224 78
Pellet stoves 8.97 3.00 313 8 32 104 132 83 Catalytic wood-‐stoves
6.00 938
The difference between poor and high standard combustion technology and emission control can be
appreciated in Table 17. High standard equipment is very effective in reducing most types of biomass
combustion emissions. Although there is a small overlap in particle emissions, facilities can take
additional measures to reduce particle emissions.
Table 17 Comparison of emissions for poor and high standard combustion furnace design [50]
Emissions at 11% O2 Poor standard High standard Excess air ratio 2-‐4 1.5-‐2 CO [mg/m3
0] 1000-‐5000 20-‐250 CxHy [mg/m3
0] 100-‐500 <10 PAH [mg/m3
0] 0.1-‐10 < 0.01 Particles, after cyclone [mg/m3
0] 150-‐500 50-‐150
5.4 Emission control measures for biomass combustion
Emission control measures can be categorized as either primary or secondary measures. Primary
emission reduction measures include feedstock treatment and combustion process design. Secondary
measures consist of downstream collection equipment that removes pollutants from combustion flue
gas.
Feedstock treatments include modification of the fuel composition, moisture content reduction, and
particle size reduction. Herbaceous feedstock contains measurable quantities of various salts and alkali
compounds. Washing, including exposing biomass to rainwater, can significantly reduce feedstock alkali
52
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
material. Controlled washing, which includes using acids and heating treatments, can be expensive but
can reduce corrosion in the boiler. Washing can increase feedstock moisture content and have adverse
effects on combustion performance such as preventing combustion temperatures from exceeding 850
°C. Low temperatures promote incomplete combustion, resulting in the increase of pollutant emissions.
Small-‐scale combustion applications may not have much choice in the feedstock size, but large-‐scale
facilities are typically optimized for a specific particle size. In large-‐scale facilities, introducing feedstock
with sizes that are larger than expected can result in incomplete combustion and increased particle
emissions.
Emission control based on combustion process design includes the selection of equipment and
process operating conditions that lead to lower emissions. Equipment selection is typically limited by
plant capacity and economic factors, but equipment can be chosen to optimize the combustion of
available feedstock. It is possible to take direct measurements of emission compounds during the
optimization of the combustion temperature, residence times, and airflow. When direct measurements
are not available, the presence of optimal quantities of excess oxygen in the combustion chamber is a
good indicator of reduced emissions. Table 18 shows a comparison of emission and efficiency
measurements taken before and after the optimization of a combustion boiler. As is shown,
optimization can significantly reduce emissions while simultaneously improve process efficiency. The
modifications include improved air to fuel ratio, flue gas recirculation, and combustion chamber design
changes.
53
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Table 18 Comparison of emission and efficiency measurements resulting from the optimization of a combustion boiler [51]
Property Before optimization After optimization 1 2 3 1 2 3 CO [mg/m3
0] 3516 4439 4327 82 313 103 CxHy [mg/m3
0] 262 303 269 2 28 2 NOx [mg/m3
0] 772 722 764 652 872 706 Dust [mg/m3
0] 219 235 214 99 157 106 Flue gas temperature [°C] 163 164 158 109 162 132 Flue gas losses [%] 17 -‐ 17 7 -‐ 8 Losses due to incomplete combustion [%] 1.5 -‐ 2.0 0.1 -‐ 0.1 Overall Efficiency [%] 81 -‐ 81 93 -‐ 92
Secondary emission control measures consist of equipment that is located downstream from the
boiler with the purpose of collecting pollutants that would otherwise remain entrained in the flue gas
stream. Secondary emission control equipment includes cyclones, bag filters, electrostatic precipitators
(ESP), and scrubbers.
The choice of emission control equipment depends on the particle size and stickiness. Cyclones are
ideal to capture non-‐sticky particles with diameter sizes of 5 mm or greater. Cyclones operate by using
centrifugal forces to push particles to wall edges where they eventually fall through the bottom while
the clean gas exits through the top. Particles that are smaller than 5 mm in diameter will remain
entrained in the gas stream. Bag filters can collect these smaller particles by providing a clothed surface
through which the gas stream can pass through and leave the particles on the surface. The efficiency of
bag filters tends to improve with time because the collected particles create a secondary surface with
even smaller pores. Some particles exhibit electrical properties, which make ESPs a very efficient
collection measure. ESPs use electrical charges to attract small particles to a surface where they remain
until the polarity is changed (for example, cleaning). Sticky particles such as tars must be collected using
wet scrubbers. Wet scrubbers employ liquid droplets to intercept particles in the gas stream. Although
water is commonly used, the type of particles collected could influence the choice of collection liquid.
54
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
5.5 Handling and applications of ash from biomass combustion
Biomass ash requires different handling measures and end-‐use applications than coal ash. Biomass
ash contains alkali material that volatilizes at combustion temperatures and forms condensable vapors
that are precursors to tar. This alkali, when processed properly, can be recycled to provide soil nutrients.
The differences between biomass ash and coal ash are significant. Therefore, knowledge gained from
the use of coal ash is not entirely applicable to biomass ash. Our fundamental understanding of how
solid residues from biomass conversion processes can interact with the soil and environment at large is
currently limited. More research is needed to better understand the relationships between feedstock,
conversion process, and residue end-‐use application for biomass technologies. Following is a discussion
on how to characterize the composition and behavior of solid residues using chemical fractionation.
Alkali metals (potassium (K) and sodium (Na)), phosphates, and some heavy metals volatilize during
biomass combustion and agglomerate into a condensable, sticky liquid. When the condensation occurs
in the boiler, the liquid is known as slag; outside the boiler the liquid tends to form tar. Both of these are
undesirable material in combustion equipment and can lead to decreases in performance and clogging if
left unchecked. Aluminum-‐silicates, unlike the previously mentioned alkali, tend to fuse into sub-‐micron
quartz and silica particles. These particles are much easier to collect, but the disadvantage is that they
can render nutrients inaccessible to plants and limit their utility for soil amendment applications.
Chemical fractionation techniques employ standardized leaching processes with chemical reagents
to characterize the inorganic components in solid fuels. Van Loo and Koppejan employed chemical
fractionation to compare the behavior of inorganic material found in various biofuels to coal. This
process involves washing a small sample with water, followed by an ammonium acetate solution, and
finally a hydrochloric acid solution [48]. This process would yield four fractions of leachable components:
1. Water -‐ alkali metal salts, sulfur, and chlorine compounds;
55
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
2. Buffer solution – organics;
3. Acids -‐ carbonates and sulphates; and
4. Residue -‐ silicates and compounds insoluble in mineral acids.
Water and acetate-‐leachable elements correspond with compounds that become entrained in the
vapor phase in the form of very fine particles and aerosols. Acid and residue fractions typically form
large particles that are much easier to collect. Figure 20 shows chemical fractionation results for
representative fossil, forest, and agricultural fuels.
0
2000
4000
6000
8000
10000
12000
Si Al Fe Ti Ca Mg Na K S P Cl
mg/kg dry fu
el
Bituminous Coal in H2O
in Ac
in HCl
in solid residue
in untreated fuel
56
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Figure 20 Bituminous coal, forest residue, and wheat straw chemical fractionation results (adapted from [48])
In general, biofuels contain larger quantities of water-‐acetate soluble fractions than coal. This
implies that biomass combustion would result in a greater amount of fine particle and aerosol
0
2000
4000
6000
8000
10000
12000
Si Al Fe Ti Ca Mg Na K S P Cl
mg/kg dry fu
el
Forest Residue in H2O
in Ac
in HCl
in solid residue
in untreated fuel
0
2000
4000
6000
8000
10000
12000
Si Al Fe Ti Ca Mg Na K S P Cl
mg/kg dry fu
el
Wheat Straw in H2O
in Ac
in HCl
in solid residue
in untreated fuel
57
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
formation. Power plants may need to invest in additional equipment to improve the collection of small
particulate matter.
Returning biomass ash to the soil can help close the nutrient cycle. Some nutrient losses will occur
during the conversion and application steps, and more research is needed to determine the leaching
behavior of recycled alkali. Combustion facilities may need to invest in quality assurance capabilities to
ensure that the ash composition meets the requirements of the soil where it will be applied. The ash
source is typically the most ideal candidate for its application (i.e. forest vs. agricultural ash), but analysis
may still be required to ensure that the ash composition did not change drastically.
An alternative market for biomass ash is found in the construction industry. Coal ash, which is rich in
aluminum-‐silicates, has traditionally been employed in asphalt mixtures. Biomass ash that cannot be
marketed for soil amendment could serve as a coal substitute for construction, landscaping, cement
blends, and as a component for lightweight aggregates. The challenge for these markets is that biomass
ash supply is typically scarce. Marketing coal and biomass ash mixtures partly solves the availability
problem, but these mixtures tend to have specific properties that make them a completely separate
product.
6 Conclusions
This report presents an overview of the economic and environmental opportunities for biomass
heat and power generation in Iowa. It includes analyses of biomass supply and availability, heat and
power applications, and economic and environmental impacts of biomass co-‐firing.
Various types of feedstock are suitable for heat and power applications. A major feedstock category
is agricultural residues such as corn stover. Corn stover is an attractive energy feedstock when available
economically in large quantities. Iowa produces 68.3 million tons per year of corn stover, which could be
58
Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
made available to energy facilities. Growth, harvest, and conversion are the key stages in the biomass
supply chain. Although there is a mature supply chain established for corn grain, there is still a lot of
work needed to develop an industrial supply chain for biomass to energy applications.
Biomass conversion to energy can take place in a dedicated heat and power generation system, in a
co-‐firing environment, or integrated in agricultural and industrial facilities. Dedicated systems employ
direct combustion, gasification, or anaerobic digestion technologies to convert biomass into heat and
power. Gas and steam turbines are commonly employed to convert a combustible gas or process heat to
electricity. Biomass co-‐firing is the practice of simultaneously combusting biomass and coal in the same
facility. Simultaneous injection, separate injection, and biomass gasification combined with coal
combustion are three approaches to biomass co-‐firing. These approaches provide a range of feedstock
flexibility, capital cost, and process efficiency for facilities to consider. Biomass can provide combined
heat and power to agricultural and industrial facilities. Corn ethanol plants in particular could reduce
their use of fossil fuels and improve their environmental profile by replacing coal or natural gas with
clean, renewable biomass.
Biomass combustion results in direct and indirect emissions in heat and power applications. Biomass
can reduce direct CO2, NOx, and SOx emissions in coal-‐fired facilities. The amount of reduction is strongly
dependent on the proportion of biomass to coal employed. Biomass could, therefore, help industrial
facilities meet governmental legislation for caps in power plant emissions. Industrial facilities that rely
on short-‐term rotation feedstock would have carbon payback periods of a few years followed by net-‐
zero or even negative carbon emissions. Most biomass combustion pollutants can be safely captured by
existing cleaning technologies. Development and optimization of these technologies would help reduce
emissions, and economic and legislative incentives could accelerate industrial efforts to meet
environmental standards.
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
Iowa has the unique opportunity to lead in the development of a biomass-‐based industry. Iowa’s
agricultural residues could become a major source of energy. This report identifies some of the major
challenges and opportunities for biomass heat and power generation. Iowa’s industrial facilities have
begun to integrate agricultural feedstock into their current operations, but the low cost of fossil fuels
has so far limited biomass adoption. Technology development will likely reduce costs and improve the
environmental impacts of biomass heat and power generation.
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Techno-‐Economic and Environmental Opportunities for Biomass Heat and Power Generation
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About the Author
Mark Mba Wright is a research assistant with the Iowa State University Department of Mechanical
Engineering. He earned his Masters of Science degree in Mechanical Engineering and Biorenewable
Technologies at Iowa State University in 2008. Mark has authored several papers on the techno-‐
economics of biofuel production, and is a co-‐author of the chapter “Capturing Solar Energy through
Biomass” in the recently released book, “Principles of Sustainable Energy.”