Performance and cost assessment of Integrated Solar Combined Cycle Systems (ISCCSs) using CO2 as heat transfer fluid

In this paper, a performance and cost assessment of Integrated Solar Combined Cycle Systems (ISCCSs) based on parabolic troughs using CO₂ as heat transfer fluid is reported on. The use of CO₂ instead of the more conventional thermal oil as heat transfer fluid allows an increase in the temperature of the heat transfer fluid and thus in solar energy conversion efficiency. In particular, the ISCCS plant considered here was developed on the basis of a triple-pressure, reheated combined cycle power plant rated about 250 MW. Two different solutions for the solar steam generator are considered and compared.The results of the performance assessment show that the solar energy conversion efficiency ranges from 23% to 25% for a CO₂ maximum temperature of 550 °C. For a CO₂ temperature of 450 °C, solar efficiency decreases by about 1.5–2.0% points. The use of a solar steam generator including only the evaporation section instead of the preheating, evaporation and superheating sections allows the achievement of slightly better conversion efficiencies. However, the adoption of this solution leads to a maximum value of the solar share of around 10% on the ISCCS power output. The solar conversion efficiencies of the ISCCS systems considered here are slightly greater than those of the more conventional Concentrating Solar Power (CSP) systems based on steam cycles (20–23%) and are very similar to the predicted conversion efficiencies of the more advanced direct steam generation solar plants (22–27%).The results of a preliminary cost analysis show that due to the installation of the solar field, the electrical energy production cost for ISCCS power plants increases in comparison to the natural gas combined cycle (NGCC). In particular, the specific cost of electrical energy produced from solar energy is much greater (about two-fold) than that of electrical energy produced from natural gas.     

Integration of Kalina cycle in a combined heat and power plant,a case study

This paper presents the integration of the Kalina cycle process in a combined heat and power plant for improvement of efficiency. In combined heat and power plants, the heat of flue gases is often available at low temperatures. This low-grade waste heat cannot be used for steam production and therefore power generation by a conventional steam cycle. Moreover, the steam supply for the purpose of heating is mostly exhausted, and therefore the waste heat at a low-grade temperature is not usable for heating. If other measures to increase the efficiency of a power plant process, like feed-water heating or combustion air heating, have been exhausted, alternative ways to generate electricity like the Kalina cycle process offer an interesting option. This process maximizes the generated electricity with recovery of heat and without demand of additional fuels by integration in existing plants. The calculations show that the net efficiency of an integrated Kalina plant is between 12.3% and 17.1% depending on the cooling water temperature and the ammonia content in the basic solution. The gross electricity power is between 320 and 440 kW for 2.3 MW of heat input to the process. The gross efficiency is between 13.5% and 18.8%.     

Off-design performance of integrated waste-to-energy,combined cycle plants

This paper focuses on the off-design operation of plants where a waste-to-energy (WTE) system fed with municipal solid waste (MSW) is integrated with a natural gas-fired combined cycle (CC). Integration is accomplished by sharing the steam cycle: saturated steam generated in a MSW grate combustor is exported to the heat recovery steam generator (HRSG) of the combined cycle, where it is superheated and then fed to a steam turbine serving both the CC and the WTE plant.Most likely, the WTE section and the natural gas-fired CC section are subject to different operation and maintenance schedules, so that the integrated plant operates in conditions different from those giving full power output. In this paper we discuss and give performance estimates for the two situations that delimit the range of operating conditions: (a) WTE plant at full power and gas turbine down; (b) WTE plant down and gas turbine at full power. This is done for two integrated plants having the same WTE section, i.e. grate combustors with an overall MSW combustion power of 180 MW_LHV, coupled with Combined Cycles based on two different heavy-duty gas turbines: a medium-size, 70 MW class turbine and a large-size, 250 MW class turbine.For each situation we discuss the control strategy and the actions that can help to achieve safe and reliable off-design operation. Heat and mass balances and performances at off-design conditions are estimated by accounting for the constraints imposed by the available heat transfer areas in boilers, heaters and condenser, as well as the characteristic curve of the steam turbine. When the gas turbine is down the net electric efficiency of the WTE section is very close to the one of the stand-alone WTE plant; instead, when the WTE section is down, the efficiency of the CC is much below the one of a stand alone CC. These performances appear most congenial to what is likely to be the operational strategy of these plants, i.e. paramount priority to waste treatment and CC dispatched according to the requirements of the national grid.     

Micro tri-generation system for indoor air conditioning in the Mediterranean climate

Mediterranean countries show two specific features regarding air-conditioning of buildings: a high—and growing—cooling load and high relative humidity, at least in coastal zones. In this contribution we report on the development of an innovative micro scale tri-generation system (power + heating + cooling), equipped with a rotor based desiccant system adapted to the Mediterranean conditions which receives heat for the desiccant regeneration from a combined heat and power (CHP) cycle.The paper presents the design of the advanced desiccant air handling unit which uses a high efficient combination of a vapor compression chiller working at a high evaporator temperature and a desiccant wheel (silica gel). The electricity of the chiller is supplied by the CHP system and the heat to regenerate the desiccant is the waste heat of the CHP. System simulations have been used to optimize the hydraulic design and the operation strategy in order to minimize operation costs and maximize energy savings. Some new component models, e.g. for the advanced desiccant cycle were developed for this purpose. The final design of the entire system consisting of the CHP system, the vapor compression chiller, the advanced desiccant air handling unit and the load system is described. The load system is composed of an air duct network with induction units and a chilled water network with fan-coils in the office rooms.Regarding energy performance results indicate an electricity saving >30% in comparison to state-of-the-art solutions based on conventional technology.     

Decarbonized hydrogen and electricity from natural gas

This paper discusses configuration, attainable performances and thermodynamic features of stand-alone plants for the co-production of de-carbonized hydrogen and electricity from natural gas (NG) based on commercially available technology.We focus on the two basic technologies currently used in large industrial applications: fired tubular reformer (FTR) and auto-thermal reformer (ATR). In both cases we assume that NG is pre-heated and humidified in a saturator providing water for the reforming reaction; this reduces the amount of steam to be bled from the power cycle and increases electricity production. Outputs flows are made available at conditions suitable for transport via pipeline: 60 bar for pure hydrogen, 150 bar for pure CO₂. To reduce hydrogen compression power requirements reforming is carried out at relatively high pressures: 25 bar for FTR, 70 bar for ATR. Reformed gas is cooled and then passed through two water–gas shift reactors to optimize heat recovery and maximize the conversion to hydrogen. In plants with CO₂ capture, shifted gas goes through an amine-based chemical absorption system that removes most of the CO₂. Pure hydrogen is obtained by pressure swing absorption (PSA), leaving a purge gas utilized to fire the reformer (in FTR) and to boost electricity production.For the power cycle we consider conventional steam cycles (SC) and combined cycles (CC). The scale of plants based on a CC is determined by the gas turbine. To maintain NG input within the same range (around 1200 MW), we considered a General Electric 7FA for ATR, a 6FA for FTR. The scale of plants with SC is set by assuming the same NG input of the corresponding CC plant.Heat and mass balances are evaluated by a model accounting for the constraints posed by commercial technology, as well as the effects of scale. Results show that, from a performance standpoint, the technologies of choice for the production of de-carbonized hydrogen from NG are FTR with SC or ATR with CC. When operated at high steam-to-carbon ratios, the latter reach CO₂ emissions chargeable to hydrogen of 10–11 kg of CO₂ per GJ_LHV—less than 20% of NG—with an equivalent efficiency of hydrogen production in excess of 77%.     

Combined cycle versus one thousand diesel power plants: pollutant emissions,ecological efficiency and economic analysis

The increase in the use of natural gas in Brazil has stimulated public and private sectors to analyse the possibility of using combined cycle systems for generation of electrical energy. Gas turbine combined cycle power plants are becoming increasingly common due to their high efficiency, short lead times, and ability to meet environmental standards. Power is produced in a generator linked directly to the gas turbine. The gas turbine exhaust gases are sent to a heat recovery steam generator to produce superheated steam that can be used in a steam turbine to produce additional power. In this paper a comparative study between a 1000 MW combined cycle power plant and 1000 kW diesel power plant is presented. In first step, the energetic situation in Brazil, the needs of the electric sector modification and the needs of demand management and integrated means planning are clarified. In another step the characteristics of large and small thermoelectric power plants that use natural gas and diesel fuel, respectively, are presented. The ecological efficiency levels of each type of power plant is considered in the discussion, presenting the emissions of particulate material, sulphur dioxide (SO₂), carbon dioxide (CO₂) and nitrogen oxides (NO_x).     

Techno-economic analysis of using corn stover to supply heat and power to a corn ethanol plant – Part 2: Cost of heat and power generation systems

This paper presents a techno-economic analysis of corn stover fired process heating (PH) and the combined heat and power (CHP) generation systems for a typical corn ethanol plant (ethanol production capacity of 170 dam³). Discounted cash flow method was used to estimate both the capital and operating costs of each system and compared with the existing natural gas fired heating system. Environmental impact assessment of using corn stover, coal and natural gas in the heat and/or power generation systems was also evaluated. Coal fired process heating (PH) system had the lowest annual operating cost due to the low fuel cost, but had the highest environmental and human toxicity impacts. The proposed combined heat and power (CHP) generation system required about 137 Gg of corn stover to generate 9.5 MW of electricity and 52.3 MW of process heat with an overall CHP efficiency of 83.3%. Stover fired CHP system would generate an annual savings of 3.6 M$ with an payback period of 6 y. Economics of the coal fired CHP system was very attractive compared to the stover fired CHP system due to lower fuel cost. But the greenhouse gas emissions per Mg of fuel for the coal fired CHP system was 32 times higher than that of stover fired CHP system. Corn stover fired heat and power generation system for a corn ethanol plant can improve the net energy balance and add environmental benefits to the corn to ethanol biorefinery.     

Investigation of coal-fired power plants in Turkey and a case study: Can plant

About 61% of the total installed capacity for electrical power generation in Turkey is provided by thermal resources, while 80% of the total electricity is generated from thermal power plants. Of the total thermal generation, natural gas accounts for 49.2%, followed by coal for 40.65%, and 9.9% for liquid fuel. This study deals with investigation of the Turkish coal-fired power plants, examination of an example plant and rehabilitation of the current plants. Studied plant has a total installed capacity of 2 × 160 MW and has been recently put into operation. It is the first and only circulating fluidized bed power plant in the country. Exergy efficiencies, irreversibilities, and improvement factors of turbine, steam generator and pumps are calculated for plant selected. Comparison between conventional and fluidized bed power plant is made and proposed improving techniques are also given for conventional plants.     

Energy policy tools for agricultural residues utilization for heat and power generation: A case study of sugarcane trash in Thailand

Cane trash could viably substitute fossil fuels in heat and power generation projects to avoid air pollution from open burning and reduce greenhouse gas (GHG) emission. It is competitive with bituminous and other agro-industrial biomass. Using cane trash for heat generation project could provide a higher reliability and return on investment than power generation project. The heat generation project could be viable (Financial Internal Rate of Return, FIRR = 36–81%) without feedstock subsidy. With current investment and support conditions, the capacity of 5 MW option of power generation project is the most viable (FIRR = 13.6–15.3%); but 30 MW, 1 MW and 10 MW options require feedstock subsidy 450–1100 Baht/t-cane trash to strengthen financial viability. Furthermore, the revenue from carbon credit sales could compensate the revenue from current energy price adder and increases 0.5–1.0% FIRR of power generation project. Using cane trash for 1 MW power generation could reduce GHG emission 637–861 t CO₂eq and avoid air pollutant emissions of 3.35 kg nitrogen oxides (NO_x), 0.41 kg sulfur oxides (SO_x) and 2.05 kg volatile organic compounds (VOC). Also, 1 t steam generation from cane trash could avoid pollutant emissions of 0.6 kg NO_x, 0.07 kg SO_x, and 0.37 kg VOC. The potential of cane trash to cause fouling/slagging as well as erosion are not significantly different from other biomass, but chlorinated organic compounds and NO_x could be higher than bituminous and current biomass feedstock at sugar mill (bagasse and rice husk).     

Aspen Plus simulation of biomass integrated gasification combined cycle systems at corn ethanol plants

Biomass integrated gasification combined cycle (BIGCC) systems and natural gas combined cycle (NGCC) systems are employed to provide heat and electricity to a 0.19 hm³ y⁻¹ (50 million gallon per year) corn ethanol plant using different fuels (syrup and corn stover, corn stover alone, and natural gas). Aspen Plus simulations of BIGCC/NGCC systems are performed to study effects of different fuels, gas turbine compression pressure, dryers (steam tube or superheated steam) for biomass fuels and ethanol co-products, and steam tube dryer exhaust treatment methods. The goal is to maximize electricity generation while meeting process heat needs of the plant. At fuel input rates of 110 MW, BIGCC systems with steam tube dryers provide 20–25 MW of power to the grid with system thermal efficiencies (net power generated plus process heat rate divided by fuel input rate) of 69–74%. NGCC systems with steam tube dryers provide 26–30 MW of power to the grid with system thermal efficiencies of 74–78%. BIGCC systems with superheated steam dryers provide 20–22 MW of power to the grid with system thermal efficiencies of 53–56%. The life-cycle greenhouse gas (GHG) emission reduction for conventional corn ethanol compared to gasoline is 39% for process heat with natural gas (grid electricity), 117% for BIGCC with syrup and corn stover fuel, 124% for BIGCC with corn stover fuel, and 93% for NGCC with natural gas fuel. These GHG emission estimates do not include indirect land use change effects.     

A novel polygeneration system integrating the acetylene production process and fuel cell

This paper presents a novel polygeneration system that integrates the acetylene process and the use of fuel cells. The system produces acetylene and power by a process of the partial oxidation/combustion (POC) of natural gas process, a water–gas shift reactor, a fuel cell and a waste heat boiler auxiliary system to recover the exhaust heat and gas from the fuel cell. Based on 584.3 kg/h of natural gas feedstock, a POC reactor temperature of 1773 K, an absorber pressure of 1.013 MPa and a degasser pressure of 0.103 MPa, the simulation results show that the new system achieved acetylene production of 1.9 MW, net electricity production of 1.7 MW, power generation efficiency of 26.8% and exergy efficiency of 43.4%, which was 20.2% higher than the traditional acetylene production process. The new system's exergy analysis and the flow rate of the products were investigated, and the results revealed that the energy conversion and systematic integration mechanism demonstrated the improvement of natural gas energy conversion efficiency.     

An innovative ceramic high temperature plate-fin heat exchanger for EFCC processes

For heat exchanger applications needing extreme operation temperatures such as in the field of power generation or heat recovery a ceramic plate-fin heat exchanger is proposed, based on the “Offset Strip Fin” design. At first the principal selection of the materials and the environmental barrier coating (EBC) needed to protect the substrate from the aggressive flue gases is explained. Then a manufacturing process is described able to incorporate the EBC on all parts having contact to the flue gases. On the basis of a representative biomass fuelled externally fired combined cycle (EFCC) process with an electrical output of 6 MW the thermal design is presented resulting in a counter flow ceramic heat exchanger block of weight 4.0 t and surface area densities of 443 mm²/mm³ on the flue gas side and 286 mm²/mm³ on the pressurized process gas side. To ensure the thermomechanical integrity investigations of both the steady state operation and the case of an emergency stop were investigated by means of finite element method (FEM). In the case of steady state operation a security factor of 8.5 was achieved. This demonstrates that the occurring stresses in both cases are controllable.     

Thermodynamic analysis of an LNG fuelled combined cycle power plant with waste heat recovery and utilization system

This paper has proposed an improved liquefied natural gas (LNG) fuelled combined cycle power plant with a waste heat recovery and utilization system. The proposed combined cycle, which provides power outputs and thermal energy, consists of the gas/steam combined cycle, the subsystem utilizing the latent heat of spent steam from the steam turbine to vaporize LNG, the subsystem that recovers both the sensible heat and the latent heat of water vapour in the exhaust gas from the heat recovery steam generator (HRSG) by installing a condensing heat exchanger, and the HRSG waste heat utilization subsystem. The conventional combined cycle and the proposed combined cycle are modelled, considering mass, energy and exergy balances for every component and both energy and exergy analyses are conducted. Parametric analyses are performed for the proposed combined cycle to evaluate the effects of several factors, such as the gas turbine inlet temperature (TIT), the condenser pressure, the pinch point temperature difference of the condensing heat exchanger and the fuel gas heating temperature on the performance of the proposed combined cycle through simulation calculations. The results show that the net electrical efficiency and the exergy efficiency of the proposed combined cycle can be increased by 1.6 and 2.84% than those of the conventional combined cycle, respectively. The heat recovery per kg of flue gas is equal to 86.27 kJ s^?1. One MW of electric power for operating sea water pumps can be saved. The net electrical efficiency and the heat recovery ratio increase as the condenser pressure decreases. The higher heat recovery from the HRSG exit flue gas is achieved at higher gas TIT and at lower pinch point temperature of the condensing heat exchanger. Copyright © 2006 John Wiley & Sons, Ltd.     

Calculation of bright roof-tops for solar PV applications in Dhaka Megacity,Bangladesh

Bangladesh has already been known as the country of power crisis. Although the country's electricity generation capacity is 4275 MW, around 3000–3500 MW of electricity can be generated against the demand of more than 5000 MW. The country's power is being generated mostly with conventional fuel (82% indigenous natural gas, 9% imported oil, 5% coal) and renewable sources (4% hydropower and solar). But recently a remarkable decline of the indigenous gas takes place, which rapidly aggravates electricity generation. Dhaka, the capital as well as prime city of the country with its nearly 14 million populations faces the worst situation due to the shortfall of electricity. Around 1000–1200 MW of electricity is supplied to Dhaka Megacity, while the existing demand is nearly 2000 MW. As a result frequent load shedding takes place and most of the service sectors in the city are interrupted, which has recently created immense dissatisfaction among the city-dwellers. Given the city's power crisis and geophysical situations, applications of either stand-alone or grid connected PV systems would be very effective and pragmatic for power supplement. The conservative calculation of bright roof-tops from the Quickbird Scene 2006 of Dhaka city indicates that the city offers 10.554 km² of bright roof-tops within the Dhaka City Corporation (DCC) ward area (134.282 km²). The application of stand-alone PV systems with 75 Wp solar modules can generate nearly 1000 MW of electrical power, which can substantially meet the city's power demand.     

Thermal performance prediction of a solar hybrid gas turbine

The present work focuses on a modelling procedure to simulate the operation of a solar hybrid gas turbine. The method is applied to a power generation system including an heliostat field, a receiver and a 36 MW commercial gas turbine. Heat is provided by concentrated solar power and integrated by fossil fuel. A detailed modelling of the gas turbine (GT) is proposed to predict the performance of commercial GT models in actual operating conditions. Advanced software tools were combined together to predict design and off-design performance of the whole system: TRNSYS® was used to model the solar field and the receiver while the gas turbine simulation was performed by means of Thermoflex®. A detailed comparison between the solarized and the conventional gas turbine is reported, taking into account GT electric power, efficiency and shaft speed. All thermodynamic parameters such pressure ratio, air flow and fuel consumption were compared. The main advantage of solarization is the fossil fuel saving, but it is balanced by a relevant penalty in power output and efficiency.     

Simulation analysis of a system combining solid oxide and polymer electrolyte fuel cells

We evaluated the performance of system combining a solid oxide fuel cell (SOFC) stack and a polymer electrolyte fuel cell (PEFC) stack by a numerical simulation. We assume that tubular-type SOFCs are used in the SOFC stack. The electrical efficiency of the SOFC–PEFC system increases with increasing oxygen utilization rate in the SOFC stack. This is because the amount of exhaust heat of the SOFC stack used to raise the temperature of air supplied to it decreases as its oxygen utilization rate increases and because that used effectively as the reaction heat of the steam reforming reaction of methane in the stack reformer increases. The electrical efficiency of the SOFC–PEFC system at 190 kW ac is 59% (LHV), which is equal to that of the SOFC-gas turbine combined system at 1014 kW ac.     

Contribution of renewable energy sources to electricity production in the La Rioja Autonomous Community,Spain. A review

The implementation of the emissions market should imbue renewable energies with a greater degree of competitiveness regarding conventional generation. In order to comply with the Kyoto protocol, utilities are going to begin to factor in the cost of CO₂ (environmental costs) in their overall generating costs, whereby there will be an increase in the marginal prices of the electricity pool.This article reviews the progress made in the La Rioja Autonomous Community (LRAC) in terms of the introduction of renewable energy technologies since 1996, where renewable energy represents approximately only 10% of the final energy consumption of the LRAC. Nonetheless, the expected exploitation of renewable energies and the recent implementation of a combined cycle facility mean that the electricity scenario in La Rioja will undergo spectacular change over the coming years: we examine the possibility of meeting a target of practical electrical self-sufficiency by 2010.In 2004, power consumption amounted to 1494 GWh, with an installed power of 1029.0 MW of electricity. By 2010, the Arrúbal combined cycle facility will produce around 9600 GWh/year, thereby providing a power generation output in La Rioja of close to 2044.7 MW, which will involve almost doubling the present output, and multiplying by 8.9 that recorded in this Autonomous Community in 2001.     

Theoretical analysis and experimental research on transcritical CO2 two stage compression cycle with two gas coolers (TSCC + TG) and the cycle with intercooler (TSCC + IC)

As one of the natural refrigerants, CO₂ is a potential substitute for synthesized refrigerants with favorable environmental properties. In order to improve the performance of the CO₂ transcritical compression cycle, the performance of the two stage compression cycle with two gas coolers (TSCC + TG) and the two stage compression cycle with intercooler (TSCC + IC) were analyzed, respectively. Under the given calculation condition, the optimum intermediate pressure of the cycle TSCC + TG and the TSCC + IC are 7.09 MPa and 5.89 MPa, and the maximal COP are 2.77 and 3.08, respectively. Range of the given evaporating temperature and outlet temperature of gas cooler, the experimental testing shows that the performance of cycle TSCC + IC are 11.88% and 10.87% better than that of the cycle TSCC + TG, respectively. Range of the given inlet temperature and cooling water volume flow of gas cooler, the refrigeration COP (COP_c) and heat COP (COP_h) of the cycle TSCC + IC are average 10.97% and 4.39% higher than that of the cycle TSCC + TG. Range of the given inlet temperature and chilled water volume flow of evaporator, the refrigeration COP (COP_c) and heat COP (COP_h) of the cycle TSCC + IC are average 10.71% and 3.67% higher than that of the cycle TSCC + TG, respectively. The error between theoretical calculation and experimental testing is not exceeds 20%.     

Integrating mid-temperature solar heat and post-combustion CO2-capture in a coal-fired power plant

This article proposed a hybrid power system combining mid-temperature solar heat and a coal-fired power plant for CO₂ capture. In this system, solar heat at around 300 °C replaces the high-quality steam extractions of the Rankine cycle to heat the feed water, so the steam that was to be extracted can expand efficiently in the high-pressure turbines. In this hybrid system, the CO₂ capture penalty is completely compensated for by the enhanced work output contributed by the solar heat. The annual solar field cost is reduced to 10.8 $/ton-CO₂, compared to 25.8 $/ton-CO₂ in a system with solar heat for direct solvent regeneration. Additionally, the mid-temperature solar heat is converted into work with an improved efficiency of 27%. Thus, this system offers a promising approach to reduce the CO₂ capture penalty in CCS with attractive cost-effective utilization of mid-temperature solar heat.     

Experimental studying of a small combined cold and power system driven by a micro gas turbine

A small combined cold and power (SCCP) system is presented. An experimental study of the performance of the SCCP system is described. The gas fuelled SCCP system uses a micro gas turbine generator set and an absorption chiller. The test facility designed and built is also described. The rated electricity power of the micro gas turbine generator is about 24.5 kW at the experimental conditions. When exhaust gas from the micro gas turbine is used to drive the absorption chiller, the rated cooling capacity is 52.7 kW without supplying fuel to burn in the absorption chiller and 136.2 kW with supplying about 78.9 kW LPG fuel to burn in the absorption chiller, respectively. Primary energy rate (PER) and comparative saving of primary energy demand are used to evaluate the performance of the SCCP system. PER of the SCCP system decreases rapidly with the decrease of electric power output when the electric power output is less than 10 kW. The calculated results also show that comparative saving of primary energy demand of the SCCP system decreases with the decrease of electric power output and the SCCP system do not save primary energy comparing to conventional energy system when the electric power output is less than 10 kW.