A hybrid solar energy system consisting of a molecular solar thermal energy storage system (MOST) combined with a solar water heating system (SWH) is presented.

The global trends for the rapid growth of distributed solar heat and power in the last decade will likely continue as the levelized cost of production for these technologies continues to decline. To be able to compare the economic potential of solar technologies one must first quantify the types and amount of solar resource that each technology can utilize; second, estimate the technological performance potential based on that resource; and third, compare the costs of each technology across regions. In this analysis, we have performed the first two steps in this process. We use physical and empirically validated models of a total of 8 representative solar system types: non-tracking photovoltaics, 2d-tracking photovoltaics, high concentration photovoltaics, flat-plate thermal, evacuated tube thermal, concentrating trough thermal, concentrating solar combined heat and power, and hybrid concentrating photovoltaic/thermal. These models are integrated into a simulation that uses typical meteorological year weather data to create a yearly time series of heat and electricity production for each system over 12,846 locations in Europe and 1,020 locations in the United States. Through this simulation, systems composed of various permutations of collector-types and technologies can be compared geospatially and temporally in terms of their typical production in each location. For example, we see that silicon solar cells show a significant advantage in yearly electricity production over thin-film cells in the colder climatic regions, but that advantage is lessened in regions that have high average irradiance. In general, the results lead to the conclusion that comparing solar technologies across technology classes simply on cost per peak watt, as is usually done, misses these often significant regional differences in annual performance. These results have implications for both solar power development and energy systems modeling of future pathways of the electricity system.

We report on life cycle assessment (LCA) of the economics, global warming potential and water (both for desalination and water use in operation) for a distributed concentrating solar combined heat and power (DCS-CHP) system. Detailed simulation of system performance across 1020 sites in the US combined with a sensible cost allocation scheme informs this LCA. We forecast a levelized cost of $0.25 kWh −1 electricity and $0.03 kWh −1 thermal, for a system with a life cycle global warming potential of ∼80 gCO 2 eq kWh −1 of electricity and ∼10 gCO 2 eq kWh −1 thermal, sited in Oakland, California. On the basis of the economics shown for air cooling, and the fact that any combined heat and power system reduces the need for cooling while at the same time boosting the overall solar efficiency of the system, DCS-CHP compares favorably to other electric power generation systems in terms of minimization of water use in the maintenance and operation of the plant.The outlook for water desalination coupled with distributed concentrating solar combined heat and power is less favorable. At a projected cost of $1.40 m −3 , water desalination with DCS-CHP would be economical and practical only in areas where water is very scarce or moderately expensive, primarily available through the informal sector, and where contaminated or salt water is easily available as feed-water. It is also interesting to note that $0.40-$1.90 m −3 is the range of water prices in the developed world, so DCS-CHP desalination systems could also be an economical solution there under some conditions.

This paper investigates the cost-effectiveness of operation strategies which can be used to abate CO 2 emissions in a local multi-energy system. A case study is carried out using data from a real energy system that integrates district heating, district cooling, and electricity networks at Chalmers University of Technology. Operation strategies are developed using a mixed integer linear programming multi-objective optimization model with a short foresight rolling horizon and a year of data. The cost-effectiveness of different strategies is evaluated across different carbon prices. The results provide insights into developing abatement strategies for local multi-energy systems that could be used by utilities, building owners, and authorities. The optimized abatement strategies include: increased usage of biomass boilers, substitution of district heating and absorption chillers with heat pumps, and higher utilization of storage units. The results show that, by utilizing all the strategies, a 20.8% emission reduction can be achieved with a 2.2% cost increase for the campus area. The emission abatement cost of all strategies is 36.6–100.2 (€/tCO 2 ), which is aligned with estimated carbon prices if the Paris agreement target is to be achieved. It is higher, however, than average European Emission Trading System prices and Sweden’s carbon tax in 2019.

Abstract:The European roadmap for the power sector dictates an 80-95% cut of existing levels of carbon dioxide emissions is needed by the year 2050 to meet climate goals. This article describes results from a linear cost optimization investment model, ELIN, coupled with a solar technology model, Distributed Concentrating Solar Combined Heat and Power (DCS-CHP), using published investment costs for a comprehensive suite of renewable and conventional electricity generation technologies, to compare possible scenarios for the future electricity grid. The results of these model runs and sensitivity analyses indicate that: (1) solar photovoltaics (PV) with battery storage will likely play a very large role in meeting European targets; (2) concentrating solar power (CSP) with thermal energy storage is at a slight economic disadvantage with respect to PV to compete economically; (3) the economic potential of wind power is only comparable with solar PV if high wind penetration levels are allowed in the best wind sites in Europe; and (4) carbon capture and nuclear technologies are unlikely to compete economically with renewable technologies in creating a low-carbon future grid.