Logistics, Costs, and GHG Impacts of Utility-Scale Cofiring with 20% Biomass Idaho National Laboratory is operated by Battelle Energy Alliance, LLC for the United States Department of Energy under contract DE-AC07-05ID14517. Pacific Northwest National Laboratory is operated by Battelle for the United States Department of Energy under contract DE-AC05-76RL01830. Technical Report INL/EXT-12-25252 PNNL-23492 June 2013 Prepared for the U.S. Department of Energy Bioenergy Technologies Office Under DOE Idaho Operations Office Contract DE-AC07-05ID14517 DISCLAIMER This information was prepared as an account of work sponsored by an agency of the U.S. Government. 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Logistics, Costs, and GHG Impacts of Utility-Scale Cofiring with 20% Biomass June 2013 Idaho National Laboratory Pacific Northwest National Laboratory Idaho Falls, Idaho 83415 Richland, Washington 99352 http://www.inl.gov http://www.pnnl.gov Contributors: Contributors: Richard Boardman Mark Bearden, Kara Cafferty James Cabe Corrie Nichol Corinne Drennan Erin Searcy Susanne Jones Tyler Westover Jonathan Male Rick Wood George Muntean Lesley Snowden-Swan Sarah Widder Prepared for the U.S. Department of Energy Bioenergy Technology Office Under DOE Idaho Operations Office Contract DE-AC07-05ID14517 (This page is intentionally left blank) ii EXECUTIVE SUMMARY This report presents the results of an evaluation of utility-scale biomass cofiring in large pulverized coal power plants. The purpose of this evaluation is to assess the cost and greenhouse gas reduction benefits of substituting relatively high volumes of biomass in coal. Two scenarios for cofiring up to 20% biomass with coal (on a lower heating value basis) are presented; (1) woody biomass in central Alabama where Southern Pine is currently produced for the wood products and paper industries, and (2) purpose-grown switchgrass in the Ohio River Valley. These examples are representative of regions where renewable biomass growth rates are high in correspondence with major U.S. heartland power production. While these scenarios may provide a realistic reference for comparing the relative benefits of using a high volume of biomass for power production, this evaluation is not intended to be an analysis of policies concerning renewable portfolio standards or the optimal use of biomass for energy production in the U.S. Four major elements comprise the assessment of economic and environmental impacts of cofiring high volumes of biomass to produce dispatchable electricity for the grid: 1. Biomass supply system logistics and feedstock preprocessing engineering: The objective of this analysis is to correlate the cost of biomass with supply system variables in order to minimize the cost of delivering biomass in a form compatible with existing coal plant infrastructure. The overall biomass feedstock costs are a sum of the cost of raw feedstock, as provided by producers at various distances from the power plant, with the cost of conversion into a uniform format that is compatible with the existing coal-feed systems and boiler operations. A centralized collection and treatment system is also considered and compared to collection and processing at distributed supply depots as a function of the biomass draw distance from the power plants. The pretreatment operations evaluated include torrefaction to increase the heating value of the biomass while also converting it to a brittle material that can be ground with the coal. Leaching is also evaluated, as applied to switchgrass to remove deleterious alkaline and chloride salts that may foul boiler heat transfer tubes and interfere with flue gas cleanup operations. 2. Power plant simulations to determine the Levelized Cost of Electricity (LCOE): A detailed Aspen Plus® process model is presented and used to determine the effects of cofiring on the cost of electricity and pollutant discharge rates for each of the coal-fired power plants selected for this evaluation. The power plant models predict the boiler performance and emissions rates for each of the cases. The results are used to estimate LCOE based on a simplified financial model that accounts for capital expenses, fuel costs, operation costs, and electricity revenues. LCOE estimates provide a useful figure of merit to compare with other renewable electricity generation options. These estimates do not account for factors such as dispatchability in real electrical power markets, where the price of electricity varies with demand and regulatory requirements. 3. Life cycle greenhouse gas (GHG) emissions estimation: Life cycle analysis (LCA) of GHG emissions is presented. Emissions for coal mining and biomass cultivation are based on studies from the literature, while emissions related to feedstock harvesting, handling, processing, and combustion at the power plant are derived from the modeling presented in the two elements above. 4. Comparison with wind- and solar-generated electricity and natural gas repowering options: The biomass cofiring cases are compared to other renewable electricity generation alternatives as well as natural gas repowering of a specific Ohio coal-fired power plant. This comparison provides insight into the potential value proposition of biomass cofiring relative to other options. LCOE calculations for natural gas assume a steady cost of fuel at 2012 market prices. [Note: By the time this report was i completed natural gas prices for the electricity market has risen from approximately $3.50 to approximately $4.50 per million Btu (MMBtu).] The basis for selecting a cofiring rate of 20% biomass centers on the assumption that this level of substitution for coal can be accomplished when providing a biomass feedstock that is compatible with the existing power plant coal conveyors, grinders, pneumatic feed lines/injectors, and burner arrangements. Untreated biomass is does not pulverize effectively with coal. Torrefaction is one method of improving the milling and grinding characteristics of biomass. Although additional work is needed to confirm this assumption, preliminary measurement of the grindability of torrefied biomass and coal indicate wood and switchgrass can be pulverized in existing coal milling operations. Higher percentages of biomass cofiring may also be possible, but are not considered in this assessment. Details about the feedstock logistics and cost models, power plant model development and validation, LCOE and LCA calculations, and a comparison with a similar cofiring study completed by the National Energy Technology Laboratory (NETL) are provided in Appendices to the report. The main body provides a summary of the key assumptions, modeling results, and general observations. Some key outcomes of the simulation predictions are tabulated here. Optimum Biomass for Lowest Biomass System & LCOE LCA Scenario 20% Cofire Supply Cost Draw Radius ($/MWh) (gCO -eq/kWh) (dry ton/yr) ($/MMBtu) 2 (miles) Alabama distributed Coal- 30.3 Coal- 1,033 Southern Pine 3 power plants ca 4 depot 4,365,000 5,860 MWe 300 Cofire- 34.4 Cofire- 868 Ohio switchgrass in centralized Coal- 27.9 Coal- 968 3 power plants 2030 ca 10 system 5,215 MWe 3,885,000 125 Cofire- 43.2 Cofire- 835 20% wind addition to wind/coal mix N/A N/A N/A not determined Alabama coal- 39.9 only portfolio 10% solar addition to solar/coal mix N/A N/A N/A not determined Alabama coal- 49.8 only portfolio Natural Gas N/A N/A N/A 43.5 675 Retrofit§ Natural Gas Repower with N/A N/A N/A 40.2 488 NGCC § Based on Integrated Environmental Control Model The relatively high cost of switchgrass reflects the higher production and preprocessing costs associated with this feedstock. An advance distributed depot biomass collection and processing system is optimum for the Alabama woody biomass scenario. A centralized biomass collection and processing system is marginally better than a distributed depot supply system for the Ohio switchgrass scenario. The benefits of a uniform feedstock based on a blend of biomass sources may reduce the fuel costs predicted in this ii study. An evaluation of feed source blending could be evaluated could be completed using the tools and approach developed for this assessment. Cofiring 20% biomass results in life-cycle CO2 emissions reductions of 16% for the Alabama coal-only case and 14% for the Ohio coal-only case. Based on the average of these results, if 20% of the coal combusted in 2010 had been replaced with biomass, CO2 emissions could have been reduced by roughly 350 million metric tons, or about 6% of net annual GHG emissions. This would have required approximately 225 million tons of dry biomass. Such an ambitious fuel substitution would require development of a biomass feedstock production and supply system tantamount to coal. This material would need to meet stringent specifications to ensure reliable conveyance to boiler burners, efficient combustion, and no adverse impact on heat-transfer surfaces and flue gas cleanup operations. Natural gas fuel switching with coal results in life-cycle CO2 emissions of 30%, while replacement of the coal plant with NGCC provides a 50% reduction relative to the Ohio coal-only power plant. The main impediment to retrofitting or repowering with natural gas is the high capital cost associated with either option. Wind and solar power additions also require a large capital project. Biomass cofiring, on the other hand, may commence without a significant retrofit to the coal plant when the feedstock is processed to resemble coal.