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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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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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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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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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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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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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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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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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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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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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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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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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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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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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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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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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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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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

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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


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


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.

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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


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


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


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


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


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


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


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


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


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


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


(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


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


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


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


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


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


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


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


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


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


Figure 15 Bioenergy and Fossil Heat and Electricity Energy System Cycles [29]

40


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


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


mg/kg dry fu

el

Wheat Straw in H2O

in Ac

in HCl

in solid residue

in untreated fuel

57


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


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.

59


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.

1


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2


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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.”

Documents

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