Coal power station. Image: iStockPhoto.

By Juergen Peterseim

However, further improvements are required to enhance economic competitiveness and raising cycle efficiency through higher steam parameters is one promising option. All energy plants under construction and in operation work with sub-critical steam parameters, such as 565 °C at 160bar. But many coal fired power stations operate with super-critical parameters instead, such as 620 °C and 280bar. This technology may be applicable to CSP too.

The first super-critical coal plants were built in the late 1950’s to raise efficiency and the technology has developed significantly ever since. For instance, it has contributed an historical increase in cycle efficiency of 3.3% and a reduction of 5.6% in capital expenditure by doubling of cumulative deployment.

Super-critical power blocks have been employed for many years now but their utilization in CSP plants have had their own challenges with regards to factors such as minimum turbine size (250 MWe); working fluids of a suitable high-temperature (>600 °C) and technology upscale.

Recently, the Commonwealth Scientific and Industrial Research Organisation (CSIRO) performed a test of super-critical steam parameters at a facility in Australia. It was a relevant first step, but the road towards achieving commercial deployment of 250 MWe is still long.

To incorporate thermal energy storage (TES) at a facility of such capacity, working fluids need to reach higher temperatures. While research published in the field has shown that molten salts can reach up to 700 °C, a commercial product is not yet available.

To justify the required effort the industry needs to understand the benefits of this technology over sub-critical plants. The following analysis compares three options for a 250 MWe air-cooled solar tower plant, with 7 hours of TES in molten salt and a single steam reheating in Australia:

    Scenario 1: Current subcritical Rankine cycle plant with steam parameters of 545 °C at 165bar. This concept could be deployed today and projects in the 250 MWe scale have already been proposed.

    Scenario 2: Solar tower heating 280bar supercritical steam to 545 °C, with solar energy plus additional natural gas superheating to reach 620 °C. This concept could be deployed today and additional steam superheating has been demonstrated in the Shams 1 plant even though at a lower steam temperature/pressure level.

   Scenario 3: Supercritical plant using 700 °C molten salt with steam parameters of 620 °C at 280bar. Such a facility is not immediately deployable as the molten salt required to reach that temperature is not yet available.

Super-critical steam plants could reach a net cycle efficiency of 43.9% for scenario 2 and 44.2% for scenario 3, compared to 41.3% in scenario 1. This is a significant increase with associated cost reduction effects.

Figure 1. Impact of the different scenarios on the solar field size. Scenario 1 = yellow field; Scenario 2 = blue field; Scenario 3 = green field.

Figure 1 illustrates the impact of the three scenarios on the solar field size. Despite having the same steam parameters, the net cycle efficiency of scenario 2 is slightly lower than scenario 3’s, because of some additional losses associated with the gas fired superheater. Raising steam parameters to 700 °C at 350bar, as proposed for the latest generation coal fired plants, would yield a net cycle efficiency of 45.6%.

Assuming plant commissioning in 2025 and continued cost reductions until then, scenario 2 would offer the lowest capital cost (USD$4.3/MWe), as part of the solar energy input is substituted by natural gas. Scenario 2 would offer $4.7m/MWe whereas scenario 1, $4.9m/MWe.

The scenario 2 plant would yield the lowest capital cost but its LCOE is, at a gas price of $5.9/GJ, with $120/MWh identical to scenario 3. A scenario 1 plant would reach $126/MWh. One might have expected a higher LCOE reduction but these analyses consider high labour cost in Australia and additional risk for a first-of-its-kind plant.

A relevant finding is the LCOE sensitivity figure in scenario 2, with regards to the gas price at US$ 10/GJ, which is the same as the LCOE in scenario 1. Besides, the use of gas slightly diminishes the environmental benefit, but the carbon intensity is, with 77kg/MWh, low.
The adoption of any new technology entails inherent technical and commercial risks. First, on-sun trials were successful but the pathway to the construction of a 250 MWe plant requires intermediate steps.

50 or even 100 MWe supercritical turbines are not available and the only option to demonstrate the technology at this scale is through the integration into a supercritical coal plant. While the hybridisation of CSP with coal is contentious, their parameters match well.

Figure 2: Example of a 100 MWe supercritical solar tower retrofit with 5 hours of advanced thermal storage, equivalent to a 2 GWe coal plant.

Figure 2 provides an example of a 100 MWe equivalent CSP retrofit with 5 hours of TES to a 2 GWe coal plant. A retrofit would not only lower production risk but costs too, as existing expensive items could be used, such as steam turbines. Considering that the solar field, receiver and TES represent approximately 60% of the capital cost, an immediate cost reduction of 40% is achievable. Maybe an older and typically smaller supercritical coal plant could even be converted to CSP.

It can be concluded that raising the steam parameters of CSP plants to super-critical levels can improve cycle efficiency and LCOE. The large scale required for such plants coincides with economy-of-scale benefits in other areas, such as civil works. It is therefore an avenue worth investigating further despite existing challenges with regards to working fluids and technology up-scale. There is sufficient engineering expertise in supercritical steam turbine systems within the coal industry. This knowledge could be transferred to CSP to improve its competitiveness.

About the author:

Dr. Juergen Peterseim finished his Industrial Engineering degree in 2003 in Germany and has since worked in the fields of renewable energy and industrial ecology with a focus on heat recovery, energy from biomass and waste, multi-fuel plants, and concentrating solar power. In 2014 he completed his PhD at the Institute for Sustainable Future (University of Technology, Sydney) on concentrating solar power hybrid plants and its potential role in the transition to a low carbon energy future. Previously and in parallel to his time at the University of Technology, Sydney he was/is the Australian Representative for the boiler design company ERK Eckrohrkessel GmbH.