Biomass Feasibility Project Final Report - Xcel Energy
Biomass Feasibility Project Final Report - Xcel Energy
Biomass Feasibility Project Final Report - Xcel Energy
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plant characteristics and plant expenses were derived from the source material. The<br />
documentation for each power plant template uses quite different financial assumptions. These<br />
were standardized across power plants, with the exception of the income escalation variable for<br />
the CHP plant, which was modified to account for the potential for rapidly increasing natural<br />
gas prices.<br />
50 MW wood- fired stoker boiler<br />
This template was generated using documentation relating to the Big Stone II coal power plant<br />
(Burns & McDonnell, 2005).<br />
The template is meant to represent the costs for a wood-fired stoker boiler built as an additional<br />
generating unit at an existing coal fired plant. The expenses included in this template include<br />
fixed O&M costs, non-fuel variable O&M costs, and insurance. In addition to wood fuels this<br />
plant is assumed to be adaptable to corn stover and switchgrass.<br />
35 MW <strong>Biomass</strong> Co-Firing (Incremental Costs) and 600 MW Pulverized Coal Plant<br />
w/ 35 MW <strong>Biomass</strong> Co-Firing<br />
The co-firing cost estimates are derived from documents published by the Chariton Valley<br />
<strong>Biomass</strong> <strong>Project</strong> (Alliant <strong>Energy</strong>, et. al., 2002) and documents relating to a proposed pulverized<br />
coal plant in South Dakota (Burns and McDonnell, 2005), The Chariton Valley documents were<br />
used to create a template for a co-firing operation that could be added to a coal plant<br />
template to estimate the blended costs of a co-firing operation. The capital costs for the cofiring<br />
template include the costs of the fuel storage, handling and processing facilities needed<br />
for a co-firing operation. The operational costs include the additional labor, administrative and<br />
maintenance costs needed to operate a co-firing operation. The cost estimates for the coal<br />
plant are meant to be representative of the expected costs for a new 600 MW pulverized coal<br />
unit built adjacent to an existing coal plant. The expenses included in this template include fixed<br />
O&M costs, non-fuel variable O&M costs, and insurance. The 35 MW Co-firing template can be<br />
used to estimate the incremental costs of a co-firing operation. The blended template including<br />
the 35 MW co-firing template and 600 MW pulverized coal plant can be utilized to estimate the<br />
average cost of energy for a co-firing operation.<br />
Industrial CHP with Gasifier and 4 X 1.3 MW Gensets<br />
This template is based on an economic and technical feasibility study of a biomass gasification<br />
CHP system at a large malting facility (Trillium Planning and Development, 2002). A number of<br />
scenarios were examined for the study. The template is based on the most economic scenario<br />
examined in the study. It includes four Jenbacher Engine sets with a total net capacity of 5.4<br />
MW. The natural gas savings from the thermal energy captured from the system are accounted<br />
for as “Other Income”. The electrical efficiency represents the Net Electrical Efficiency based on<br />
the energy content of the biomass prior to gasification, not the electrical efficiency of the<br />
combustion of syngas by the turbine or genset. The operating costs included in this template<br />
include labor, maintenance and the cost of standby electrical service.<br />
135 kW Genset w/ Manure Digester<br />
This template is based on the Haubenschild Dairy Farm Digester near Princeton, MN (Kramer,<br />
2004). The farm operates a plug-flow digester that powers a 135 kW engine generator set.<br />
Thermal energy recovered from the genset’s cooling jacket is used to heat the barn. The<br />
electrical efficiency represents the system efficiency taking into account the efficiency of the<br />
Identifying Effective <strong>Biomass</strong> Strategies: Page 129<br />
Quantifying Minnesota’s Resources and Evaluating Future Opportunities