Exergetic, environmental and economic analyses of small-capacity concentrated solar-driven heat engines for power and heat cogeneration
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In this paper, the exergy interactions, environmental impact in terms of CO2 mitigation, and the economics of small-capacity concentrated solar power-driven heat engines for power and heat generation are analysed for residential applications. Starting from a base case study that assumes mass production in Ontario, it is shown that the investment in such a system, making use of a heat engine and having 9 m2 of aperture area, could be about CN$10 000 for a peak electrical efficiency of 18% and thermal efficiency of 75%. The average CO2 mitigation due to combined savings in electricity and heat is ∼0.3 kgCO2 kWh−1, a figure 3–4 times larger than for photovoltaic panels. If 25% government subsidy to the investment is provided, the payback period becomes 21.6 years. Additionally, if the financing benefits from a feed-in-tariff program (at 25% electrical sell-back to the grid) and deductions from CO2 tax are realized, then the payback time drops to 11.3 years. These results are obtained for a conservative scenario of 5.5% annual incremental increase in energy price. For the moderate consideration of all factors, it is shown that within the financial savings over the entire lifecycle, 7% are due to carbon tax, 30% are due to electrical production and the largest amount, 63%, is the result of reducing the natural gas heating capacity with solar heating from the proposed system. Copyright © 2011 John Wiley & Sons, Ltd.Keywords:
Cogeneration
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Economic feasibility of microturbine cogeneration systems in consideration of payback period as an evaluation criterion is investigated based on parametric analysis of the capital unit cost and power generating efficiency of microturbine cogeneration units. For this analysis, a method to clarify the relationships between the payback period and the aforementioned parameters by combining a nonlinear equation problem on the payback period with an optimal unit sizing problem to minimize the payback period. Based on this method, a map expressing the combination of the parameters for a target payback period is illustrated. Through numerical studies for a hotel, the economic feasibility of the microturbine cogeneration system is clarified and the annual primary energy consumption and CO_2 emission are evaluated.
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The objects of the research are the solar photovoltaic systems (PV) that generate a significant amount of the electrical consumption in the building. This paper describes the parameters that affect the payback period of photovoltaic systems. Analysis of the first year of use of specific photovoltaic system (Building of a warehouse in Pärnu) is presented. The paper contains a analysis of the actual payback of photovoltaic systems under different scenarios of changes in electrical tariffs in the future. If calculating based on positive scenario (significant increase of tariffs) return of investment for specific PV in Pärnu is 9,5 years. If the increase in tariffs is minimal (negative scenario), the return of investment will two years later.
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This report examines Swedish cogeneration importance for the domestic energy system and
for the North European power exchange. Carbon dioxide emissions and generation cost of
Swedish cogeneration is compared to imported or that by export replaced average electricity
to and from Sweden. The comparison is for a historic period (2005-2010) where known
annual electricity exchange data and cogeneration generation by fuel is used to compare
actual emissions and cost. And a future period (2011-2020) based on the NREAP report,
where projected electricity and cogeneration investments are used to estimate future CO2-
emissions and generation cost. Also the new Rya NGCC CHP plant is compared to the North
European marginal electricity generation for the historic period (2005-2010). The comparison
is based on emissions of CO2, NOx and SOx.
The method uses fixed values for emissions factors, generation prices and fuel to energy
efficiencies based on qualified sources for average values. The comparison is visualised in
both diagram and tables.
The result implies that the imported electricity has lower CO2-emissions compared to Swedish
cogeneration. However when removing Norway from the comparison the result is different,
now the imported electricity has higher CO2-emissions. The comparison for Swedish
cogeneration and the by export replaced abroad average electricity is different annually
depending on how much electricity Sweden exports to Norway. Removing Norway from the
comparison makes Swedish cogeneration better from an emission point of view.
The estimated generation cost of both imported and exported electricity is lower than Swedish
cogeneration, even when the heat income from sold heat is accounted for. If Norway is once
again removed from the comparison , the results shows that the generation cost of both the
imported and by export replaced average electricity is similar to Swedish cogeneration. As
cogeneration also generates useful heat it can be assumed to be a better alternative compared
to the average electricity generation in these countries. Swedish cogeneration can however not
compete with the cheap and emission free Norwegian hydro power.
Future CO2-emissions will decrease faster for the North European average electricity
compared to Swedish cogeneration, but will still be higher. The cost of generating this
electricity will still be higher than Swedish cogeneration but the gap will decrease. Sweden
will based on the results join Norway and generate enough CO2-free electricity by 2015 to
meet its annual domestic needs.
The efficient Rya NGCC CHP has lower emissions compared to marginal electricity in
Northern Europe. The use of natural gas which is the cleanest fossil fuel alternative and the
lower average efficiency in the abroad power generation makes Rya a relatively clean facility.
Especially when keeping in mind the high heat demand that exists in Gothenburg’s urban area
during winter season when Rya is operated.
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In this study, the suitability of using cogeneration system for the Aktürk Building Complex (located in İstanbul) was investigated using electricity and heat consumption data by considering five different cogeneration system capacities (800, 1200, 1400, 2000 and 2600 kW). The different capacities were compared using data of the payback period of investment, amount of net savings, ratio of meeting demand and part-load efficiency of the cogeneration system. Although payback periods of the investment for different capacities are close to each other, 1200 kW capacity cogeneration system is proved to be suitable for the Aktürk Building Complex because it has the shortest payback period (1 year 5 months).
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<p>Cogeneration or Combined Heat and Power (CHP) is defined as the sequential generation of two different forms of useful energy from a single primary energy source.This paper deals with a comparison study on the aspects of energy efficiency and energy economics in commercial building and industrial plant utility using conventional system and cogeneration system. This study presents the performance test result of micro turbine cogeneration application (60 kW) pilot project in comercial building and optimization of existing cogeneration system (40 MW) at utility plant of industry. The micro turbine cogeneration application for generating electricity and hot water while médium scale of gas turbine cogeneration is introduced in order to improve plant efficiency of existing steam turbine cogeneration. We found that cogeneration would be a financially viable option for building and for small and large size industrial plants. </p><p><strong>Key words</strong>: Cogeneration; energy efficiency; gas turbine; microturbine; steam turbine.</p>
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Cogeneration plants, which simultaneously produce electricity and heat energy have been introduced increasingly for commercial and domestic applications in Korea because of their energy efficiency. The optimal plant configuration of a specific commercial building can be determined by selecting the size and the number of cogeneration systems, auxiliary equipment based on the annual demands of electricity, heating and cooling. In this study, a mixed-integer, linear programming, utilizing the branch and bound algorithm was used to obtain optimal solution. Both the optimal configuration system equipment and the optimal operational mode were determined based on the annual cost method for installation of a cogeneration system to a hospital and a group of apartments in Seoul, Korea. In addition, the economic evaluation for the optimal cogeneration system depending on the fuel tariff system was calculated. A short payback period and a high internal rate of return on the initial investment were found to be essential for the adoption of cogeneration plants to hospitals and apartments.
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Cogeneration systems can simultaneously produce electricity and heat energy. Applications of cogeneration systems have been increased in residential buildings and factories in Korea. In order to optimize the configuration of cogeneration, a capacity based on the pattern of annual demands of electricity, heating and cooling of application site are considered. This paper describes energy demands patterns and rate of power to heat based on electricity and heat loads in dormitory. In addition, It describes the optimal a capacity of the cogeneration system and payback period in university dormitory. The optimal design for cogeneration system with the increase of the capacity considering life cycle cost(LCC) analysis has been performed in the dormitory. In spite of the fact that previous LCC analysis was based on the monthly energy consumption, the developed LCC analysis was based on the heat-power rate according to hourly energy consumption. So developed LCC analysis anticipated the operation rate of cogeneration system more correctly. Variables used in LCC analysis are electricity cost escalation rate, interest rate, and service lives. In addition, the payback period for the optimal cogeneration system depending on the energy tariff system was calculated. When cost of electricity system multiplies 2.2, a payback period becomes 10 years in 60 kW capacity of a cogeneration system.
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The viability of a cogeneration project is affected by a number of factors. A model has been developed to analyse the economics of retrofitting cogeneration to sites with suitable heat and power demands. The model compares the cost of operating the gas turbine cogeneration plant with the cost of generating the heat in gas fired package boilers and purchasing the electricity from the local Council, and calculates a simple payback period for the cogeneration unit. The model allows optimisation of the electrical size, the heat to power ratio and the operating hours of a gas turbine powered cogeneration installation so as to minimise the payback period. The optimum arrangement depends on the buyback arrangements available for surplus electricity, and for different buyback prices there are widely different solutions. Once the situation has been optimised, the model allows easy sensitivity analysis of the other variables involved. This analysis shows that the payback period is sensitive to buyback rates, electricity prices and gas prices, in that order.
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How to determine the cost allocation is a very controversial issue in cogeneration.However,in most of the discussions,they are all directed at the small unreheat cogeneration,there is no exact introduction on cost allocation of the large reheat cogeneration.This paper put forward the formula of cost allocation which is applied to the large reheat cogeneration,and compared with unreheat cogeneration.It is proposed that rational cost allocation is still an issue to be solved for the development of cogeneration in theoretical.
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