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Repowering a Steam Turbine-Generator Power Plant Through Heat Recovery Type Combined Cycle: Selection of the Cycle — A Case Study FREE

[+] Author Affiliations
H. A. Bazzini

Bella Vista, Buenos Aires, Argentina

Paper No. 96-GT-530, pp. V004T10A033; 12 pages
doi:10.1115/96-GT-530
From:
  • ASME 1996 International Gas Turbine and Aeroengine Congress and Exhibition
  • Volume 4: Heat Transfer; Electric Power; Industrial and Cogeneration
  • Birmingham, UK, June 10–13, 1996
  • Conference Sponsors: International Gas Turbine Institute
  • ISBN: 978-0-7918-7875-0
  • Copyright © 1996 by ASME

abstract

Much of the steam-turbine based, power generating units all over the word are more than 30 years old now. Within a few years they will face the possibility of retirement from service and replacement. Nonetheless some of them are firm candidates for repowering, a technology able to improve plant efficiency, output and reliability at low costs.

This paper summarizes a study performed to establish the feasibility to repower a 2 × 33 MW steam turbine power plant and the procedure followed until selection of the steam cycle more suitable to the project. The preferred solution is compared with direct replacement of the units by a new combined cycle.

Various repowering options were reviewed to find “beat recovery” type repowering as the best solution. That well-known technology consists of replacing the steam generator by a gas turbine coupled to an HRSG, supplying steam to the existing steam turbine.

Three “GT+HRSG+ST” arrangements were considered. Available gas turbine-generators — both industrial and aero-derivative type —, were surveyed for three power output ranges. Five “typical” gas turbine-generator classes were then selected.

Steam flow raised at the HRSG, gross and net power generation, and heat exchanging surface area of the HRSG, were calculated for a broad range of usually applied, steam turbine throttle conditions. Both single pressure and double pressure steam cycles were considered, as well as supplemental fire and convenience of utilizing the existing feed water heaters. Balance of plant constraints were also reviewed.

Estimates were developed for total investment, O&M costs, fuel expenses, and revenues. Results are shown through various graphics and tables. The route leading to the preferred solution is explained and a sensitivity analysis added to validate the selection.

The preferred solution, consisting in a Class 130 gas turbine in arrangement 1–1–2, a dual-pressure HRSG and a steam cycle without feed-water heaters, win allow delivering 200 MW to the grid, with a heat rate of 7423 kJ/kW-hr. Investment was valued at $MM77.0, with an IRR of 15.3%. Those figures compare well with the option of installing a new GTCC unit: with a better heat rate but an investment valued at $MM97.5, its IRR will only be 12.4%.

Copyright © 1996 by ASME
This article is only available in the PDF format.

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