Towards a Techno-Economic Framework for Estimating Cost-Performance Trade-offs for Power Plants Incorporating Transformative Dry-Cooling Technologies
Fresh water withdrawal for thermoelectric power generation in the U.S. is approximately 139 billion gallons per day (BGD), or 41% of total fresh water draw, making it the largest single use of fresh water in the U.S. Of the fresh water withdrawn for the power generation sector, 4.3 BGD is dissipated to the atmosphere by cooling towers and spray ponds. Dry-cooled power plants are attractive and sometimes necessary because they avoid significant withdrawal and consumption of freshwater resources that could otherwise be used for other purposes. This could become even more important when considering the potential effects of climate change (1). Additional benefits of dry-cooling include power plant site flexibility, reduced risk of water scarcity, and faster permitting (reducing project development time and cost). However, dry-cooling systems are known to be more costly and larger than their wet-cooling counterparts. Additionally, without the benefit of additional latent heat transfer through evaporation, the Rankine cycle condensing (cold) temperature for dry-cooling is typically higher than that for wet-cooling, affecting the efficiency of power production and the resultant levelized cost of electricity (LCOE).
The Advanced Research Projects Agency – Energy (ARPA-E) has developed a technoeconomic analysis (TEA) model for the development of indirect dry-cooling systems employing steam condensation within a natural gas combined cycle power plant. The TEA model has been used to inform the Advanced Research in Dry-Cooling (ARID) Program on the performance metrics needed to achieve an economical dry-cooling technology. In order to assess the relationship between air-cooled heat exchanger (ACHX) performance, including air side heat transfer coefficient and pressure drop, and power plant economics, ARPA-E has employed a modified version of the National Energy Technology Laboratory (NETL) model of a 550 MW natural gas combined cycle (NGCC) plant employing an evaporative cooling system. The evaporative cooling system, including associated balance of system costs, was replaced with a thermodynamic model for an ACHX with the desired improved heat transfer performance and supplemental cooling and storage systems. Monte Carlo simulation determined an optimal ACHX geometry and associated ACHX cost. Allowing for an increase in LCOE of 5%, the maximum allowable additional cost of the supplemental cooling system was determined as a function of the degree of cooling of the working fluid required. This paper describes the methodologies employed in the TEA, details the results, and includes related models as supplemental material, while providing insight on how the open source tool might be used for thermal management innovation.