Article pubs.acs.org/EF
Determination of Emission Factors for Co-firing Biomass and Coal in a Suspension Fired Research Furnace L. Jia,* P. Geddis, S. Madrali, and F. Preto Natural Resources Canada, 1 Haanel Drive, Ottawa, Ontario, Canada K1A 1M1 ABSTRACT: New regulations implemented by the Canadian federal government to limit greenhouse gas (GHG) emissions from coal burning power plants had sparked intense activity in the utility industry to find ways to reduce emissions. Several studies have indicated that carbon capture and storage (CCS) is not going to be economically available in the short term. Cofiring biomass appears to be an option for many of the coal-fired power plants, as Canada has a significant amount of biomass resources. Although biomass combustion can reduce greenhouse gas emissions, it can also generate other air pollutants. To determine emission factors for co-firing biomass and coal, pilot-scale tests were performed. These tests were conducted in CanmetENERGY’s 0.5 MWth pilot-scale pulverized fuel research furnace, which was configured with a dual-burner system, electrostatic precipitator, and baghouse. Gaseous emissions were recorded with two monitoring systems, and traditional methods for batch sampling of halogens, mercury, and particulate matter were implemented. Emission factors were developed for a 100% coal baseline, for two co-firing ratios of 20% and 55% biomass by heating value and biomass-only firing.
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INTRODUCTION In 2011, Canada’s utilities produced 552 terawatt-hours of electricity,1 with about 13% generated from coal. In the fall of 2011, the Canadian federal government published new regulations to reduce GHG emissions from coal fired electricity.2 The CO2 emission intensity limit for power generation had been set at, on average, no more than 420 tonnes CO2 emitted per GWh of electricity in a calendar year. The new regulations came into full force for new power projects on January 1, 2013, and for older installations on July 1, 2015. For the existing operational coal-fired generating stations, co-firing biomass with coal represents one possible option for reducing CO2 emissions. Co-firing can therefore facilitate a plants’ ability to meet the recently imposed federal regulations on GHG emissions. It capitalizes on the large investment and infrastructure associated with the existing fossilfuel-based power systems (including fuel shipment and storage facilities as well as flue gas cleaning installations), while requiring a relatively modest investment.3 Utilizing biomass fuels has also indirect benefits to the forestry and the secondary wood products industry4 by providing new markets for residues, thereby promoting economic stability in the region and the potential to develop feedstock infrastructure and jobs for long-term biomass development and use. Co-firing of biomass and coal is a proven technology, with particular experience in Europe in biomass co-firing.5−8 Up to 10% of the coal is typically displaced by biomass. The biomass and coal are usually combusted simultaneously, but may be injected separately at different locations in the combustion chamber to account for the differences in burn-out time. When used as a supplemental fuel in an existing coal-fired boiler, biomass can provide certain benefits: lower fuel costs, more fuel flexibility, reduced NOx emissions, and reducing waste to landfills.9 Although biomass combustion can reduce greenhouse gas (GHG) emissions relative to fossil fuels, it can also generate other air pollutants, which without proper control can create © 2016 American Chemical Society
local and/or regional air quality impacts. The amount of pollutants emitted to the atmosphere from various types of biomass combustion applications is highly dependent on the combustion technology implemented, the fuel properties, the combustion process conditions, and the primary and secondary emission reduction measures that have been implemented.10 To obtain an objective view of emissions from biomass combustion applications, it is necessary to collect emission data from a wide range of fuel/technology combinations. The US EPA in its AP-4211 has identified 90 organic compounds (or groups of compounds) and 26 trace elements (metals) in the emissions from wood combustion. The state of Washington in 2005 developed emission factors for over 90 chemicals12 and then conducted a risk assessment, including air dispersion modeling to determine “candidate pollutants of concern” which, based on their analyses, represent the most significant emissions from wood fired boilers. Among others, this list includes volatile organic compounds (VOCs), polycyclic aromatic hydrocarbons (PAHs), metals, and particulate matters, among others. Nussbaumer and Hustad13 presented typical ranges of emissions from various types of wood furnaces (understoker, grate firings, and dust/suspension firings). The emission levels from high performance furnace designs can be 10 times lower compared with poorly designed ones for CO, CxHy, and PAHs. They have also indicated that emissions such as HCl, NOx, and metals are directly related to biomass fuel properties. Urban waste wood and demolition wood have much higher emission levels than virgin wood for these pollutants. Trace elements present in biomass fuels are related to the biomass species, growing site, and age of the plants.14 The utilization of biomass and wastes as fuels also introduces Received: May 13, 2016 Revised: July 26, 2016 Published: July 27, 2016 7342
DOI: 10.1021/acs.energyfuels.6b01157 Energy Fuels 2016, 30, 7342−7356
Article
Energy & Fuels Table 1. Fuel Characterization Results for Test Coal and Biomass PRB Coal
Biomass
Proximate Analysis
Test Moisture
Dry at 105 °C
Dry Ash Free
Ash Volatile Matter Fixed Carbon Moisture Total
8.40 38.15 48.94 4.50 100.00
8.80 39.95 51.25
43.80 56.20
Ultimate Analysis
Test Moisture
Carbon Hydrogen Nitrogen Sulfur Oxygen Ash Moisture Total Gross Calorific
65.67 4.35 0.98 0.84 15.24 8.40 4.50 100.00 26.44 11,366
100.00 PRB Coal Dry at 105 °C 68.76 4.56 1.03 0.88 15.96 8.80 100.00 27.68 11,902 PRB Coal
100.00 Dry Ash Free 75.4 5.00 1.13 0.97 17.5
100.00 30.35 13,050
Test Moisture
Dry at 105 °C
Dry Ash Free
0.58 72.16 14.26 13.00 100.00
0.67 82.94 16.39
83.50 16.50
100.00 Biomass
Test Moisture 43.12 5.34 0.18 0.00 37.77 0.58 13.00 100.00 17.19 7,392 Biomass
Forms of Sulfur
Dry at 105 °C
Dry at 105 °C
Total Sulfate Pyritic Organic
0.87 0.05 0.47 0.35
0.02
