Biomass fuels: Biomass fuel summary

Bioenergy Processing Articles >> Biomass

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Biomass facilities convert biomass into a useable and more valuable product. Although biomass conversion is most often associated with electrical power generation, many other energy and non-energy products can also be produced from biomass.

Non-energy products include compost, wood pellets, charcoal, and fiber. This report does not consider non-energy biomass conversion for several reasons. First, a composting or wood pellet processing would be in direct competition with existing private companies. Second, composting and wood pellet processing would be unlikely to provide the level of economic benefit or job creation that the County is seeking through biomass opportunities. And third, although charcoal manufacturing can be profitable, it is a very competitive business dominated by large and well established producers.

Biomass can also be converted into biofuels such as methanol, ethanol, and biodiesel. Production of biofuels requires a more advanced and costly biomass facility, but the biofuel has a significantly higher selling price compared with electricity, steam, and non-energy products. Biomass ethanol is traditionally produced through the hydrolysis of corn and other high-sugar or high-starch crops. Hydrolysis was not considered as a viable technology for Yakima County because of fuel availability and economics; however, the production of ethanol through gasification is discussed in this report.

Steam and electricity are the most common outputs associated with biomass-to-energy facilities. Combined heat and power (CHP) projects generate both steam and electricity as marketable products, and can achieve high efficiencies. CHP is typically more economically viable than electricity-only projects, but a CHP facility must be located directly adjacent to a large user of steam. An obstacle to an electricity-only biomass project is the low price of electricity in the Pacific Northwest. The energy products described here can be created from biomass fuels through several types of technology. The rest of this section discusses three types of biomass-toenergy technology that might be feasible given the availability of fuel sources and potential customers for energy products in Yakima County. These are combustion, gasification, and anaerobic digestion.

2.1 Combustion
Combustion is the oldest technology for biomass conversion, especially for generating heat and steam from woody fuel. A biomass combustion facility can produce steam, electricity, or both (CHP). A boiler furnace burns the biomass to create steam. If electrical output is desired, a steam-turbine generator is used to convert a portion, or all, of the steam to electricity.

Combustion technology is typically the lowest-cost biomass-to-energy technology to construct and operate, especially for woody fuels. Combustion boilers can be designed to burn almost any type of biomass fuel, including dry manure and MSW. Fuels can be mixed to cope with diversity in the fuel supply or to provide optimum combustion performance. Table 1 in the previous section provides average combustion heat rates of different fuels, and Table 3 provides average costs of combustion technologies.

Ash is a waste product of biomass combustion. The amount of ash produced depends on the fuel (e.g., MSW combustion results in far more ash than combustion of mill residues). Ash represents a disposal cost for the biomass facility. Sometimes ash can be land-applied or mixed into compost, but most often it is landfilled. The four common combustion boiler designs are: pile burners, stoker-fired furnaces, suspension-fired furnaces, and fluidized bed furnaces.

- Pile Burners—Pile burners or “Dutch ovens” are the oldest and simplest boiler design, but have low efficiencies and poor combustion control. The advantage of pile burners is a simple and low-cost design and fuel flexibility. Although many older pile burners are still in operation, they are not recommended for modern commercial-scale biomass-to-energy projects.

- Stoker-Fired Furnaces—Stoker-fired furnaces can have sloping fixed grates, traveling grates, or vibrating grates. Fixed sloping grates are the simplest design, but have the least amount of fuel control. Traveling grates provide an improvement in fuel control, but have higher maintenance due to the moving parts. Vibrating grates, sometimes called “reciprocating grates,” are very common in modern biomass combustion facilities. Of all the stoker designs, vibrating grates can handle the greatest variations in fuel types and mixtures, fuel size, and moisture content. Stoker furnaces are a proven and tested technology for biomass combustion.

- Suspension-fired Furnaces—Suspension-fired furnaces inject finely pulverized fuel in a high-speed air stream for combustion. The fuel burns while suspended in the air stream. This technology is common for coal-fired boilers and achieves high efficiency, but processing biomass into the finely pulverized powder is difficult and costly. The fuel for suspension-fired furnaces typically must be smaller than a 1/4-inch particle size and have a moisture content less than 15 percent. Suspension firing of biomass is normally only feasible in special situations where sawdust or other ultra-dry wood waste is co-fired or used as a retrofit fuel in a coal-fired boiler.

- Fluidized Bed Furnace—Fluidized bed furnaces are the newest furnace technology, although the technology has been widely used for several decades. The furnace bed consists of particles of sand and limestone or other inert materials. These furnace bed materials are fluidized (suspended) by high-velocity high-temperature air, and the fuel is injected into the turbulent mixture. Fluidized bed combustors can be classified as bubbling fluidized bed (BFB) or circulating fluidized bed (CFB), depending on the air velocity. CFB combustors operate at high enough air velocities that the bed material is carried out of the combustion chamber with the hot gases and must be circulated back into the combustion chamber through cyclone separators.

One advantage of fluidized bed furnaces in biomass combustion is the ability to handle a wide range of fuels and moisture content. Fluidized bed furnaces achieve the highest thermal conversion efficiencies of any boiler technology because of more complete combustion of the fuel. More complete combustion also results in lower emissions and ash quantities compared to other combustion process. However, fluidized bed systems are expensive to construct and have significant maintenance requirements. The combustion air fans and additional mechanical load of the fluidized bed process also means that the facility consumes a higher percentage of the energy produced compared to other boiler types, although this is typically compensated for by the higher energy recovery out of the fuel. When used for biomass combustion, some fluidized bed furnaces have had corrosion problems with high-alkali fuels such as agricultural wastes and animal manures.

In spite of the apparent advantages of fluidized bed furnaces, stoker furnaces dominate the biomass combustion industry. Stokers have a proven track record for biomass combustion, and the lower construction and maintenance costs offset the possible incremental gains from fluidized bed technology.

2.2 Gasification
Gasification is the thermo-chemical reduction of a fuel without direct combustion. Gasifiers operate at high temperatures and pressures in an oxygen-depleted environment to convert a feedstock to a combustible gas.

The immediate product of gasification is synthetic gas, or “syngas.” Syngas consists of carbon monoxide and hydrogen, with smaller amounts of carbon dioxide and methane. Syngas will contain other compounds, such as sulfur and nitrogen, depending on the chemical makeup of the fuel. Raw syngas is not an end product, but requires further processing. Syngas can be burned to create heat, steam, or electricity. It can be converted to methane and fed into a natural gas distribution system. Syngas can also be converted to methanol, ethanol, and other chemicals or liquid fuels. Methanol produced through gasification can be further refined into biodiesel with addition of vegetable oils or animal fats. Slag is produced as a waste product of the gasification project. This is similar to the bottom ash produced by combustion, but gasification slag is denser and has a more “glassy” consistency compared with combustion ash.

Gasification is not limited to biomass fuels. Coal and other hydrocarbon fuels can be gasified, as can tires and refuse fuels. Almost any material can be “gasified” under the correct conditions. Historically, gasification has been part of the chemical and petroleum processing industry, and gasification has been used mostly in the production of chemicals.

The biomass gasification opportunities most often cited are fueled by forestry residues, agricultural residues, and MSW. Although low-efficiency and small-scale gasification of wood chips has been performed for decades, large-scale biomass gasification technology is still in the development and demonstration stage. Several small biomass gasification research and demonstration projects currently operate. Section 4 of this report describes a facility planned for La Grande, Oregon that would be one of the first commercial-scale biomass gasification projects. The two most prevalent technologies for commercial-scale gasification are fluidized bed reactors and plasma arc reactors. Fluidized bed reactors operate on the same principles as fluidized bed combustors, but are controlled so that the fuel only gasifies and is not allowed to combust. Plasma arc reactors have been used to incinerate MSW and hazardous or medical wastes. Both technologies provide very high energy conversion rates. The choice of fluidized bed vs. plasma arc technology would depend on the fuel and application.

Gasification is receiving significant attention in both the biomass-to-energy and traditional fossil energy industries. In the fossil energy industry, gasification allows electrical generation from “dirty” fuels like coal to achieve emission levels similar to those of “clean” natural gas power plants. In the biomass-to-energy industry, gasification allows production of higher-value products such as methanol and ethanol. The following paragraphs describe some of the emerging applications of gasification that may be appropriate for Yakima County.

- Electrical Generation—For generating electricity, integrated gasification combined cycle (IGCC) technology provides exceptionally high conversion rates. IGCC will generate the most electrical power per unit of biomass of any currently available technology. IGCC uses a combustion turbine fueled by syngas, with hot exhaust from the combustion turbine directed through a heat recovery steam generator (HRSG) to drive a secondary steam turbine. This combined cycle process is the same technology used for modern natural-gas-fired generating stations. IGCC is applicable to both fossil fuel gasification and biomass gasification.

- Biomass-Ethanol—Biomass-ethanol has traditionally been manufactured through hydrolysis of starchy agricultural feedstocks such as corn. Advanced technologies are being developed to produce ethanol through direct fermentation of syngas into ethanol. This technology advancement may make it viable to produce ethanol from low-sugar-content feedstocks such as forestry residues.

Gasification is an expensive technology to design, construct, operate, and maintain. Gasification facilities require considerable preparation and drying of biomass fuels, and also require substantial heat input into the gasifier unit itself. Studies have indicated that biomass gasification facilities, especially ethanol production facilities, benefit from economies of scale and need to be quite large to be viable. Although the IGCC efficiency is attractive and ethanol production from syngas is promising, currently gasification faces significant economic and technological barriers.

2.3 Anaerobic Digestion
Anaerobic digestion is a process that uses bacteria to break down biomass in an oxygen-free environment. Anaerobic digestion is common in wastewater treatment and industrial waste processing, and can also be effective in treating animal manures and wastes. It is an especially effective way to process dairy manure slurry. Anaerobic digestion produces biogas, sometimes called “digester gas,” a mixture of mostly methane and carbon dioxide. The biogas can be flared, used to generate heat or electricity, or can be converted into biofuels such as methanol. The most common application is to use the biogas to power an internal combustion engine generator to produce electricity. Exhaust heat from the engine can be circulated back into the digester to increase the rate of biogas production.

Anaerobic digestion of dairy manure has many environmental benefits. In fact, the value of energy production is typically a secondary consideration compared with the environmental benefits. Digestion significantly reduces odors and flies, and reduces pathogens. The effluent of digestion is relatively clean and can be used for irrigation or dairy stall flushing with fewer environmental and health concerns compared with typical flush waters. Digestion also produces a high-quality fiber, which can be used for livestock bedding, compost, or soil enhancement as a rich fertilizer. This fiber has a marketable value, and in some digestion demonstration projects, the sale of fiber has generated as much revenue for the dairy as has the sale of electricity.

Anaerobic digestion of dairy manure is widely practiced in Europe because of stricter environmental regulations, lack of available farmland for disposal of manure, high energy costs, and proximity of urban populations to livestock and dairy operations (and thus greater odor and fly control concerns). Anaerobic digestion has been slower to gain acceptance in the North American dairy industry, but the barriers are economic rather than technical. Most industry experts agree that the development of dairy waste anaerobic digestion in North America will be driven by tightening environmental restrictions on manure handling and disposal rather than profit from selling electricity. Many different types of anaerobic digestion systems are used to process industrial and other wastes. For dairy industry wastes, the three most common digesters are the covered lagoon, plug-flow, and complete mix. Covered lagoon and plug-flow systems are low-rate digesters, and are only applicable as integrated systems on individual dairies. Complete mix systems achieve faster conversion rates. There are several subcategories of complete mix systems, which are defined by the number of stages, bacteria films, and operating temperatures.

Construction of a dairy manure digester represents a significant investment for an individual dairy farmer, and so far, no dairy in Yakima County has built such a project. However, a large-scale centralized digester processing the wastes from multiple dairies across Yakima County could possibly achieve economies of scale not available to the individual farms.

For a centralized dairy manure digester project, manure slurry would be transported by truck from the dairies to the digester. As mentioned previously in Section 1.2, the cost and logistics of transporting large quantities of manure has been prohibitive to centralized anaerobic digestion in the United States. It might be possible to locate the digester such that one or two dairies could pipe their manure rather than using trucks. The dairy operators would also need to be able to transport the processed effluent from the digester back to their dairies to offset the amount of fresh water required for the flush systems.

A centralized dairy manure digester would need to achieve high throughput rates and biogas production to be cost effective. Also, the facility would be rather large, as the volume of manure slurry is significant. Assuming 25 percent of the milking cow manure in Yakima County was transported to the digester on a daily basis, the influent to the project would be on the order of 550,000 gallons per day. Assuming a digestion process with a relatively fast 20-day average retention time, the anaerobic digestion system would need a capacity of 11.0 million gallons of manure slurry. For comparison, the three anaerobic digesters at the Yakima Regional Wastewater Treatment Facility hold a combined 1.6 million gallons of wastewater sludge. Anaerobic digestion produces very small amounts of energy compared with other opportunities such as the combustion of woody fuels. As previously mentioned, the real benefit and motivation of digestion is the mitigation of a waste problem, not production of energy. Even at the large scale of 550,000 gallons per day, the anaerobic digester would only produce about 3 to 4 MW of electricity.

Energy Northwest has been analyzing the financial feasibility of large- and small-scale dairy waste digestion, and their analysis has indicated that to break even, a digester project would need to sell power at a wholesale rate of about $0.070 per kWh. Traditionally, the wholesale electricity rates for Washington State have been about $0.020 to $0.025 per kWh at the Mid-Columbia hub.

Duke Energy also undertook a major study in the mid-1990s, and calculated that a digester would need to collect tipping fees of at least $6 per ton to break even. An anaerobic digester project would not be economically successful based solely on the sale of electricity or steam. Sale of fiber would help to supplement the revenue of the facility, but the real economic balance would need to come from tipping fees charged to the manure suppliers.

2.4 Biomass Technology Energy Output and Costs
Table 3 provides typical statistics for biomass-to-electricity projects. The three combustion projects and the one gasification project are set to identical outputs of 25 MW. The gasification project requires about 10 percent less fuel to reach the same output because of the high efficiency of IGCC technology; however, the capital and operating costs for this technology are significantly higher. The MSW-fueled project has the highest capital and maintenance cost of all, but these high costs would be offset through tipping fees.

The most striking comparison is between the first four projects and the anaerobic digestion project. Anaerobic digestion requires over three times the amount of fuel by weight, but produces only about one-eighth the electrical output. The capital cost of the digester is similar to that of the gasification project on a per-kilowatt basis, but the operating cost is even higher.

by Yakima County Public Works, Solid Waste Division
From 'Review of Biomass Fuels and Technologies', 2003

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