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Energetic and Economic Performance of a Compressed Air Energy Storage Facility in Texas as a Function of Technical and Cost Parameters

[+] Author Affiliations
Aaron K. Townsend, Michael E. Webber

The University of Texas at Austin, Austin, TX

Paper No. IMECE2011-63830, pp. 313-321; 9 pages
doi:10.1115/IMECE2011-63830
From:
  • ASME 2011 International Mechanical Engineering Congress and Exposition
  • Volume 4: Energy Systems Analysis, Thermodynamics and Sustainability; Combustion Science and Engineering; Nanoengineering for Energy, Parts A and B
  • Denver, Colorado, USA, November 11–17, 2011
  • Conference Sponsors: ASME
  • ISBN: 978-0-7918-5490-7
  • Copyright © 2011 by ASME

abstract

In this research an optimization model was used to determine the sensitivity of the revenue, net cash flow (defined as revenue less amortized capital costs, fixed and variable operating costs, and return on investment), and operational characteristics of a compressed air energy storage (CAES) facility to certain technical factors in the Electric Reliability Council of Texas (ERCOT) zonal market. The technical factors considered were compressor capacity and storage capacity relative to turbine capacity, non-spinning reserve market participation, minimum allowable runtime of the compressor and turbine systems, and costs associated with startup of the compressor and turbine systems. Additionally, the work showed that the nine-year optimization problem could be decomposed into nine single-year optimization problems with decreased computation time and minimal divergence from the nine-year solution. Previous work had determined the optimal compressor and storage capacities for a given expander capacity; the current work expanded on the previous work to show that the economics of CAES are reasonably insensitive (defined as within 5% of the maximum net cash flow) to compressor capacity within a range of 0.45 to 0.8 MW per MW of turbine capacity in the West zone of ERCOT and 0.25 to 0.5 MW per MW of turbine capacity in the non-West zones in ERCOT. Similarly, the economics of CAES are reasonably insensitive to storage capacity within a range of 20 to 60 MWh per MW of turbine capacity in the West zone of ERCOT and 12 to 35 MWh per MW of turbine capacity in the non-West zones. Previous work had determined that participation of the turbine-generator system in the non-spinning reserve market increased the revenues and net cash flow and reduced the amount of electricity bought and sold in the balancing energy market. This work confirmed the previous finding and also determined that the participation of the motor-compressor as dispatchable load in the non-spinning reserve market increased the revenues and net cash flow and increased the amount of electricity bought and sold. The increase in electricity sales due to the motor-compressor participation in the non-spinning reserve market only partially offset the decrease in the amount of electricity sold due to the turbine-generator participation. The net effect of both systems participating in the non-spinning reserve market was an increase in revenue of 29% to 37% and net cash flow of 130% to 250% and a decrease in the amount of electricity bought and sold by about 10%. This work also found that a CAES facility is sensitive to minimum runtime constraints and startup costs. Minimum runtime constraints reduce the net cash flow by 11% to 13% and increase the amount of electricity bought and sold by 1% to 3%, for a minimum runtime of 4 hours. The effect of startup costs is to reduce both the net cash flow by 5% to 6% and the amount of electricity bought and sold by 4% to 5% for startup costs of $2/MW-start.

Copyright © 2011 by ASME
Topics: Energy storage

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