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bioweb.sungrant.org » Technical » Biopower » Technologies » Combustion » Co-firing

Co-fire	Printer Friendly

Biomass co-firing involves the partial substitution of fossil fuels with biomass resources to generate electricity. While co-firing can involve substitution of gaseous materials such as biomass-derived biogas or syngas with natural gas, typically it refers to the substitution of coal with solid biomass resources.   A number of coal electricity generating technologies can be adapted for co-firing including stoker fired, cyclone, pulverized coal, and fluid bed boilers. Selecting the technology to be used is a function of matching the biomass fuel qualities with the boiler (Atwood, 2007). Co-firing allows utilities to take advantage of the high efficiencies obtained in large coal-fired power plants; is a lower capital cost option to increase the use of biomass to produce power relative to dedicated direct fire biomass facilities; reduces the demand pressure for biomass resources relative to 100% biomass plants while still substantially increasing biomass use if widely adopted; reduces emissions of greenhouse gases and other pollutants; and improves combustion due to the higher volatile content of the biomass feedstock.

Biomass Co-Fire Technologies
Co-firing technologies can generally be divided into two broad categories--direct and indirect technologies.  Direct co-firing is where the coal and the biomass are burned together.  The biomass fuel may be introduced using the existing coal sizing, feeding, and combustion equipment. Generally the amount of biomass fuel used is between 2 and 10% (by weight) of the amount of coal used. Alternatively, the biomass fuel may be introduced separately as pre-treated material. This method allows a larger percent of biomass fuel to be used and allows more flexibility in the biomass feeding system. Most co-firing in the U.S. uses the direct method.   The in-direct method of co-firing refers to the combustion or gasification of the biomass fuel separately from the coal, and either the heat, steam, or product gases are then integrated into the coal-fired operation. These systems appear to be more popular in Europe (plants in the Netherlands, Finland and Denmark) than in the U.S.  Indirect technologies are more complex to build and operate than direct technologies, but advantages include the coal and biomass being kept separate which allows them to be used as by-products; separate biomass fuel systems which overcome limitations of the existing coal-firing equipment; coal-firing operations that could continue to operate should any problems develop with the biomass system; and systems that may accommodate the use of biomass fuels with natural gas, and that allow the use of biomass fuels with difficult to manage characteristics.   Stoker and fluidized bed units are generally more flexible in the handling of fuels than other coal technologies and typically require less modification to permit the use of biomass fuels. Larger and more diverse particle sizes are generally accepted. For example, fluidized bed combustors accept a variety of fuel sizes ranging from sawdust to 3 inch chips, and moisture content levels of 35-60%. An even spread of the fuel over the grate may require some modification to the boiler.   Globally, co-firing is most widely conducted in fluidized bed units.   Pulverized coal and cyclone boilers require smaller, more uniform sized particles, requiring the biomass particles to be reduced in size. The biomass fuel may be blended into the coal during processing, but the difference in weight per volume must be accounted for lest the lighter biomass feedstock ends up on top of the mixing unit. Alternatively, the biomass may be added separately to the combustion stream. Pulverized coal units are the most prevalent technology used globally, and thus offer the greatest opportunity to expand the use of co-firing due to the large number of facilities. However, these units require retrofitting in order to co-fire biomass.    Technical issues faced in co-firing related to the characteristics of the biomass fuel include carbon burnout; fuel preparation and handling; slagging, fouling and corrosion; ash management; and pollutant and trace element emissions. The extent of the problems encountered varies as a result of the different combustion system-feedstock combinations, but from a technical perspective, can be managed.

Biomass Co-Fire Feedstock Issues
Almost any biomass feedstock can be used if the biomass material is correctly sized for the burn unit. Currently, wood is the most common biomass feedstock used in co-firing because in many applications, wood waste material can be used with little preparation. For other biomass feedstocks, sizing and transportation may be major issues. Advances in harvesting and collection technologies may be needed to reduce the size of crop residues and grasses relative to baling which is currently used.   Industrial wood waste products, produced on a continuous basis, normally do not require large amounts of storage space. Biomass feedstocks whose availability is more seasonal (e.g., crop residues, dedicated energy crops) will require longer term storage. Biomass moisture content will more likely be important for long-term storage and processing rather than for combustion given that the percent of biomass will be less than 25% by weight. The low energy density characteristic of biomass feedstocks increases the cost of transporting the material from the collection site to the conversion facility. In one ongoing project in Centerville, Iowa using a dedicated crop, the costs of harvest, storage, transportation and processing came to $62 per ton at the boiler, not including a return to the producer.

Co-fire Testing in the U.S.
Biomass co-firing opportunities are being evaluated at several power plants in the U.S. (RRI, 2006).   The Allen (TN) power plant project focused on co-firing moderate levels of wood waste with coal in a cyclone boiler. Wood/coal blends of up to 20% wood/80% coal were burned. A variety of coal types were evaluated including Eastern high sulfur coal and Utah bituminous coal.  In some cases waste tires were also added to the fuel mix. Co-firing reduced SO2, NOx, and fossil-derived CO2 emissions relative to coal alone, and achieved a reasonable trade-off between boiler efficiency and fuel use.   At the Kingston and Colbert (TN) power plants, low percentage co-firing was tested using <5% sawdust by weight in pulverized coal facilities. The facilities were found to operate adequately in a stable state.   Low percentage co-firing (<3% by weight) of sawdust and other wood waste was tested at the Shawville Generating Station, a pulverized coal facility. Co-firing did not compromise boiler stability, operability, or efficiency, however, some difficulties were experienced with feeding more fibrous materials into the pulverizors which limited their capacities due to reduced feeder rates.   The Southern Company has conducted extensive co-firing testing at two pulverized coal boiler locations. At the Hammond (GA) plant, co-firing wood resulted in modest losses of boiler efficiency; higher quantities of unburned combustibles; increased mill energy requirements when the wood and coal were ground together; decreased mill fineness; no positive impacts on emissions; and the boiler was able to operate at full capacity. At their Kraft (GA) plant, a pulverized unit was equipped with a separate wood feeding system that directed a flow of dry sawdust into the exhauster of the bowl mill (define?). Wood and coal were co-fired with each being fired in separate burner rows. It was shown that high percentages of wood could be co-fired in a pulverized coal boiler using a separate dedicated wood feeding system.    Biomass Co-Firing Economics. Co-firing economics depend primarily on the conversion technology and the cost of the feedstock. Retrofitting of existing coal-fired utilities generally involve modifications to the fuel-handling and storage systems and possibly to the burner to permit biomass. Costs can increase substantially if the biomass feedstock needs to be dried, reduced in size, or the boiler requires a separate feeder (DOE, 2000). Investment costs to accommodate co-firing are estimated to range from $100-$700/kW of biomass capacity, with a median of $180-$200/kW (Bain, 2003). Cyclone boilers offer the lowest cost opportunities.

References
Bain, R.L., W.A. Amos, M. Downing, and R.L. Perlack. 2003. Highlights of biopower technical assessment: state of the industry and the technology.  NREL/TP-510-33502.  National Renewable Energy Laboratory, Golden, CO. Bio-fuels Industries, info@cogeneration.net S. Laux, J. Grusha, and D.A. Tillman, Co-firing of Biomass and Opportunity Fuels in Low NOx Burners, presented at 25th International Technical Conference On Coal Utilization & Fuel Systems, Clearwater, FL., March 6-9, 2000 Alan Teel, BME Consulting, LLC ateel9835@msn.com D.A Tillman and P, Hus, Blending Opportunity Fuels with Coal for Efficiency and Environmental Benefit, presented at 25th International Technical Conference on Coal Utilization & Fuel Systems, Clearwater, FL. March 6-9, 2000 D.A. Tillman, Co-firing Biomass for Greenhouse Gas Mitigation, presented at Power-Gen 99, New Orleans, LA, November30-December 1, 1999 Dave Tillman, David Johnson, Bruce Miller, Analyzing Opportunity Fuels for Firing in Coal-fired Boilers, presented at Coal Utilization Conference, Clearwater, FL, March10-13, 2003 Energy Products of Idaho, Coeur d’Alene, Idaho, Epi2@energyproducts.com U.S. Department of Energy, National Renewable Energy Laboratory (June 2000). Biomass Cofiring: A Renewable Alternative for Utilities, Biopower Fact Sheet, DOE/GO-102000-1055.