Thermoeconomical َAnalysis Of Miscellaneous Co-Generathion Of Heat and Electricity Solar Systems
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Editing a long period program for makingefficient the supply part has a positive effect on the country ,s economy and developing Iran,s function in the world energy market.one of the greatest consequenses in making efficient the supply part is yield,s improvement and the reduction of producing environmental pollatants orginated from producing energy .
Several approaches in energy distribution section are presented: spontaneous production of electricity and heat .cooling the entered air into the gas turbine .usage the expansion turbine and choosing the appropriate mixture in distribution of energy carriers are some of approaches.
In the present study long-term program of using the simultaneous production units of heat and electricity that is prepared according to the minimization of the total economic prices of energy –supllying system.investment component operating cost and fuel prices has been considered.
In termoeconomic part, photovoltaic system because of having better efficiency was put under consideration.It show that the suspense ofbuilding itwith the power 703 wh will cost 18620000 Rials a month that It’s durability is between 10 to 12years .also we compared this suspens with the consumptional electric price during 12 years.Keywords:
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Pakistan is the world’s sixth-most populous country with a semi-industrialized economy. It has been always an energy importer and dependent on fossil fuels. Great pressure is imposed on Pakistan’s national grid from the rise in fossil fuel costs, variations in the annual interest rate, and increased costs of greenhouse emissions. To meet the ever-increasing energy demand, the Government of Pakistan has decided to further harness wind and solar energies currently having a negligible share in Pakistan’s energy portfolio. Despite the importance of this issue, no study has been conducted so far on the cogeneration of power, heat, and hydrogen in Pakistan. Accordingly, this study is aimed at technical–economic–environmental sensitivity analysis of supplying electric and thermal loads of a residential building in Karachi by an off-grid wind-solar-fuel cell system. To this end, 4500000 possible cases were analyzed, simulated, and optimized with the HOMER software using 20-year average meteorological data from the NASA website. A sensitivity analysis was performed on this system for the first time in Pakistan. The other novelties are the use of dump loads for converting the surplus electricity into heat and also heat recovering in the fuel cells. The results showed the great potential of the station understudy for supplying the required power and heat by renewable energies. Hydrogen production was also affordable at every emission penalty price with an interest rate of less than 9%. Moreover, dump loads play a key role in supplying the thermal demand. Comparison of the wind turbine–solar cell–fuel cell–battery system with the wind turbine–solar cell–battery and solar cell–battery systems indicated that the internal rate of return and the payback period were, respectively, 9.39% and 11.4 years and 11.7% and 11 years. According to these results, it is recommend that Pakistani authorities promote the use of renewable energies through incentives and investment subsidies.
Cogeneration
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This paper describes a simulation model, MEDEE 2, designed to evaluate the long-term energy demand of a country, in combination with a scenario description of the main aspects of the country's social, economic, and technological evolution. This approach considers in a detailed way a national energy demand pattern and breaks down the total demand in a multitude of end-use categories (e.g., residential space heating, service sector cooling, gasoline for intercity cars). By means of this detailed investigation of energy demand we are better able to take into account the influence on energy demand of changes in social needs, economic growth, government policies, or technologies, especially in the present context of high energy prices. In addition, it makes possible the identification of the potential market (i.e. maximum demand that can be technically met) of each final energy form (e.g., electricity, coal, gas, solar, oil products, and district heat).
The model calculates useful energy demand in each end-use category for which several energy forms can be used, thus determining the substitution possibilities in energy use. This useful energy matches the energy service needed by the consumer (e.g., heat, mechanical energy). Useful energy differs from final energy, purchased by the consumer, by the efficiency of the enduse appliances. Each useful energy demand is then converted into a demand for final energy, taking into account the fuel mix (i.e., the fraction of the demand supplied by each fuel) and the end-use efficiencies of each fuel. This approach-estimating useful energy-is necessary if one wants to account for the differences in fuel efficiencies: for the same service (let us say 1 kwh of heat) the final demand will vary according to the fuel type because of these different efficiencies (e.g., 1 kwh of electricity, 1.35 kwh of gas, 1.50 kwh of oil, and 2 kwh of coal).
The total final demand is projected in MEDEE 2 for the following types of final energy forms: fossil fuel '(substitutable use of coal, oil, and gas), electricity, motor fuel, coke, feedstock, solar, and district heat.
MEDEE 2 is driven by a set of scenario elements, the evolution of which is defined in a scenario. The core of the scenario is a characterization through these elements of the development pattern of the country under consideration (life-styles, economic growth patterns, etc.). The scenario description is complemented with technological parameters (e.g., insulation standards, efficiencies, fuel mix), the evolution of which is specified in a way consistent with the macroeconomic assumptions.
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energy demand
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Thermal efficiency alone is an insufficient measure of the profitability requirement that electric power companies have on their power plants, in particular with the advent of deregulated electricity markets. In the present paper, this issue is illustrated with a study on the combined-cycle plant, where the benefit of various turbine entry temperatures and various materials for the first stage of the gas turbine is studied. The deviation in net present value is calculated, and it is shown how the possible profit to be made from more advanced materials and cooling is highly dependent upon electricity and fuel prices, whereas, the intervals for blade replacement during planned stops have a smaller impact on power plant profitability. This paper was presented at the ECOS'00 Conference in Enschede, July 5-7, 2000
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In this paper the financial viability of a novel storage concept, referred to as 'integrated pumped-heat-electricity storage', is assessed for both a coal-fired and a combined cycle (CC) power plant located in Germany, as well as for a concentrated solar power (CSP) plant located in Spain. The rationale of this concept is to use electricity during times of cheap wholesale market prices, e.g. stemming from a high supply of renewable energies, in order to generate thermal energy via a heat pump, since thermal energy can be stored at comparatively low cost. If the electricity demand rises again, the stored thermal energy is used to power a conventional water-steam cycle, thereby reducing the amount of fossil fuels used or enlarging the operating time of a CSP plant. A mixed integer linear program, considering the day-ahead wholesale market electricity prices and remunerations of offering tertiary control power in Germany, is employed to find an approximation of the optimal schedule for the generation in the power plant as well as for the purchase and the sale of electricity. The financial viability is assessed using net present value (NPV) and real options analysis. Storing electricity to profit from temporal arbitrage is found to be unprofitable, since the (conservatively estimated) costs of thermal storage units are still too high. The largest part of the revenues stems from the remunerations of offering tertiary control power. Therefore, while the utilization of heat pumps, which are estimated to have rather high costs, is not profitable, employing electric heaters without storage units is found to be economically viable for a coal-fired and a CC power plant in Germany. Here, NPV and real options analysis yield the same result, i.e. to invest immediately in such an application. In Spain, offering tertiary control power is presently not remunerated, but only the call-offs of tertiary control energy, which are not considered in the mixed integer linear program. Consequently, employing electric heaters in CSP plants in Spain is found to be not financially viable either.
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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.
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European energy systems are in a period of significant transition, with the increasing shares of variable renewable energy (VRE) and less flexible fossil-based generation units as predominant factors. The supply-side changes are expected to cause large short-term electricity price volatility. More frequent periods of low electricity prices may mean that electric use in flexible heating systems will become more profitable, and such flexible heating systems may, in turn, improve the integration of increasing shares of VRE. The objective of this study is to analyze the likely future of Nordic electricity price levels and variations and how the expected prices might affect the use of electricity and thermal storage in heat-only district heating plants. We apply the North European energy market model Balmorel to provide scenarios for future hourly electricity prices in years with normal, high, and low inflow levels to the hydro power system. The simulation tool energyPRO is subsequently applied to quantify how these electricity price scenarios affect the hourly use of thermal storage and individual boilers in heat-only district heating plants located in Norway. The two studied example plants use wood chips or heat pump as base load representing common technologies for district heating in Norway. The Balmorel results show that annual differences in inflow is still a decisive factor for Norwegian and Nordic electricity prices in year 2030 and that short-term (daily) price variability is expected to increase. In the plant-level simulations, we find that tank storage, which is currently installed in only a few district heating plants in Norway, is a profitable flexibility option that will significantly reduce the use of fossil peak load in both biomass and heat-pump-based systems. Installation of an electric boiler in addition to tank storage is profitable in the heat pump system due to the limited capacity of the heat pump. Electricity will hence, to a large extent, replace gas when heat demand exceeds the capacity of the heat pump. For the bio-based plant, we find that an electric boiler in addition to tank storage is not profitable in the normal electricity price scenario. The electric boiler investments are only profitable when electricity prices are as low as in the high inflow scenario. In that case the electric boiler will provide 17% of the heat supply in the example plant. Fuel prices for peak load and electricity grid tariffs are found to be decisive factors for the electricity use – and therefore flexibility options – provided by heat-only district heating plants.
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Part of the U.S. Initiative on Joint Implementation with the Ukraine Inter-Ministerial Commission on Climate Change, financed by the US Department of Energy. The project was implemented by a team consisting of the US company SenTech, Inc. and the Ukrainian company Esco-West. The main objective of the effort was to assess available alternatives of Ivano-Frankivsk (I-F) District Heating repowering and provide information for I-F's investment decision process. This study provides information on positive and negative technical and economic aspects of available options. Three options were analyzed for technical merit and economic performance: 1. Installation of cogeneration system based on Gas Turbine (GT) and Heat Recovery Heat Exchanger with thermal capacity of 30 MW and electrical capacity of 13.5 MW. This Option assumes utilization of five existing boilers with total capacity of 221 MW. Existing boilers will be equipped with modern controls. Equipment in this Option was sized for longest operating hours, about 8000 based on the available summer baseload. 2. Installation of Gas Turbine Combined Cycle (GTCC) and Heat Recovery Steam Generator (HRSG) with thermal capacity 45 MW and electrical capacity of 58.7 MW. This Option assumes utilization of five existing boilers with total capacity of 221 MW. Existing boilers will be equipped with modern controls. The equipment was sized for medium, shoulder season thermal load, and some cooling was assumed during the summer operation for extension of operating hours for electricity production. 3. Retrofit of six existing boilers (NGB) with total thermal capacity of 255.9 MW by installation of modern control system and minor upgrades. This option assumes only heat production with minimum investment. The best economic performance and the largest investment cost would result from alternative GTCC. This alternative has positive Net Present Value (NPV) with discount rate lower than about 12%, and has IRR slightly above 12%. The lowest economic results, and the lowest required investment, would result from alternative NGB. This Option's NPV is negative even at 0% discount rate, and would not become positive even by improving some parameters within a reasonable range. The Option with Gas Turbine displays relatively modest results and the NPV is positive for low discount rate, higher price of sold electricity and lower cost of natural gas. The IRR of this alternative is 9.75%, which is not very attractive. The largest influences on the investment are from the cost of electricity sold to the grid, the heat tariff, and the cost of natural gas. Assuming the implementation of the GTCC alternative, the benefit of the project is also reflected in lower Green House Emissions.
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The constraint contains two elements, namely the heat losses and the electricity consumption for pumping at the producer. The aim was to achieve the lowest acceptable costs in an operation. The options with the supply temperature at the area starting point set to 80/60, then 60/40, and eventually 50/30 (low temperature, 4 th generation district heating) were tested. The balance between the savings due to lower heat losses and the electricity consumption of pumps could be performed to assess the economic viability of the solution. This means that if the electricity price is sufficiently high, the model will always choose to minimize electricity consumption and thereby, maximise the profit from high temperature difference. Results concerning heat losses consider both experiences of proper insulation of pipes with variety of design outdoor temperatures (DOTs) and long term measurements from a pump station for district heating (DH) network in Canberra, Australia. We also noted that the heat energy tariffs and purchase price of electricity affect a lot optimal configuration of a DH system. For the best scenario, solutions are obtained that reach over 12% of the available saving potential after calculating 11 equations. Knowing that the policy is updated on a case study base, this is considered a promising result.
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To permit an economic evaluation of solar industrial process heat systems, a methodology to determine the annual required revenue and the internal rate of return was developed. First, a format is provided to estimate the solar system's installed cost, annual operating and maintenance expenses, and net annual solar energy delivered to the industrial process. Then an expression is presented that gives the annual required revenue and the price of solar energy. The economic attractiveness of the potential solar investment can be determined by comparing the price of solar energy with the price of fossil fuel, both expressed in levelized terms. This requires calculation of the internal rate of return on the solar investment or, in certain cases, the growth rate of return.
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