Breakeven Electricity Selling Price Research Articles

Integration of compressed air energy storage with wind generation into the electricity grid

Integration of renewable electricity from wind farms into the electricity grid presents challenges because wind is a highly variable resource whereby the amount of power generated depends on local wind speed, air density and wind turbine characteristics. Energy storage is one possible approach to mitigate power fluctuations and quality issues. Among presently available technologies to store energy, Compressed Air Energy Storage (CAES) shows many attractive features. This work focuses on techno-economic modelling and analysis for the integration of wind turbines with CAES into the power grid. To have a deep understanding of the performance, characteristics and benefits of system integration, technical and economic models for CAES processes are developed in the processes simulation software ECLIPSE. To conduct this study, two scenarios that are each dependent on generation scales and locations were proposed; (1) centralised CAES (based on the diabatic method) (2) distributed CAES (based on the adiabatic approach). The nominal power generation of centralised and distributed CAES systems were given as 280 MWe and 5 MWe, respectively. The impact of CAES systems on the electricity market is also discussed. Techno-economic analysis of the modelled centralised CAES system showed round-trip efficiency of around 53.6% (and around 56.7% for the modelled distributed CAES system). Specific investment was found to be around €585/kWe (€2452/kWe) and break-even electricity selling price to be around €111/MWh (€275/MWh). Their CO2 emissions were found to be compatible with the average CO2 emissions of UK CCGT power generation.

Techno-economic study of compressed air energy storage systems for the grid integration of wind power

Integrating variable renewable energy from wind farms into power grids presents challenges for system operation, control, and stability due to the intermittent nature of wind power. One of the most promising solutions is the use of compressed air energy storage (CAES). The main purpose of this paper is to examine the technical and economic potential for use of CAES systems in the grid integration. To carry out this study, 2 CAES plant configurations: adiabatic CAES (A-CAES) and diabatic CAES (D-CAES) were modelled and simulated by using the process simulation software ECLIPSE. The nominal compression and power generation of both systems were given at 100 and 140 MWe, respectively. Technical results showed that the overall energy efficiency of the A-CAES was 65.6%, considerably better than that of the D-CAES at 54.2%. However, it could be seen in the economic analysis that the breakeven electricity selling price (BESP) of the A-CAES system was much higher than that of the D-CAES system at €144/MWh and €91/MWh, respectively. In order to compete with large-scale fossil fuel power plants, we found that a CO2 taxation scheme (with an assumed CO2-tax of €20/tonne) improved the economic performance of both CAES systems significantly. This advantage is maximised if the CAES systems use low carbon electricity during its compression cycle, either through access to special tariffs at times of low carbon intensity on the grid, or by direct coupling to a clean energy source, for example a 100-MW class wind farm.

Techno-economic Modelling of Large Scale Compressed Air Energy Storage Systems

Interest in integrating energy storage systems into the power grid has increased in Europe over the past decade due to strategies to overcome the intermittent nature of renewable electricity sources. One of these technologies is compressed air energy storage (CAES). The main purpose of this paper is to examine the technical and economic potential of CAES systems. In this work, two configurations a) Adiabatic Compressed Air Energy Storage (A-CAES); and b) Conventional Compressed Air Energy Storage (C-CAES) were modelled using the ECLIPSE suite of process simulation software. The nominal compression and power generation of both systems were given at 100MWe and 140MWe respectively. For each mode of operation an energy analysis was carried out. Energy use was calculated and compared for each system mode. Based on the results of mass and energy balances, an economic evaluation of the systems was conducted. Technical results showed that the overall efficiency of the A-CAES system would be 64.7%, considerably better than that of the C-CAES system at 52.6%. However it could be seen in the economic analysis that the breakeven electricity selling price (BESP) of the A-CAES system was 152€/MWh, much higher than that of the C-CAES system at 95€/MWh on average.

Potential of brown algae for sustainable electricity production through anaerobic digestion

This paper assesses the economics of heat and power production from the anaerobic digestion (AD) of brown algae (Laminaria japonica) at a plant scale of 400,000 dry tons/year. The conversion process was simulated in Aspen Plus v.8.6 to obtain rigorous heat and material balance for energy assessments and the development of a techno-economic model. The breakeven electricity selling price (BESP) was found to be 18.81 ¢/kWh assuming 30years of plant life and a 10% internal rate of return. The results show that the AD unit has the highest energy demand in the entire process and consumes approximately 14% of all electricity produced. In addition, the seaweed cost of 11.95 ¢/kWh is the largest cost component that contributes to the calculated BESP, which means that a reduction in the cost of seaweed cultivation can significantly decrease the electricity production cost. A sensitivity analysis was performed on the economic and process parameters in order to assess the impact of possible variations and uncertainties in these parameters. Results showed that solids loading, anaerobic digestion yield, and time, respectively, have the highest impact on BESP.

Comparative techno-economic analysis of biomass fuelled combined heat and power for commercial buildings

The technical, environmental and economic analysis of two small scale biomass fuelled CHP applications is the subject of this study. For this analysis, the process simulation software ECLIPSE is used. Modelling and simulation have been conducted over two configurations: Organic Rankine Cycle (ORC) based and biomass gasification based systems for generating heat and electricity. The nominal power outputs of both systems are given at around 150kWe. Based on the results achieved, the key technical and environmental issues have been examined. The study also investigates the impact of different biomass feedstock on the performance of CHP systems. Finally, an economic evaluation of the system is performed. According to the ECLIPSE simulation, the overall efficiencies of the ORC based CHP system are around 76% when willow chip was used and around 81% with miscanthus. The difference was found to be due to the moisture content. For the biomass gasification based CHP system, the overall efficiencies of CHP were found to be around 58% with willow chip and 64% with miscanthus. These values are better than for any other biomass-fired electricity generation technologies of similar scale. On the other hand, the results of the economic analysis demonstrated that the breakeven electricity selling price (BESP) for the ORC-CHP systems varies from 40 to 50£/MWh and for the biomass gasification based CHP systems was between 87 and 97£/MWh. These values could be further improved if agricultural or forestry wastes could be used at lower costs.

Pre-combustion carbon-capture technologies for power generation: an engineering-economic assessment

SUMMARY An engineering-economic analysis of the behaviours of each of two pre-combustion gas-turbine combined cycles with CO2 capture (an Integrated Gasification Combined Cycle (IGCC) and an Integrated Reforming Combined Cycle (IRCC)) is described. Their economic performances have been evaluated in terms of the break-even electricity selling price. The results show that the proposed pre-combustion power plant efficiency values (37% and 43.7% for the IGCC and the IRCC respectively) are significantly lower compared to a conventional plant value (55.3%). The CO2 emissions of the latter are less than half those of the conventional plant. Introducing an hypothetical carbon tax equal to 50£/tCO2, the break-even selling price (BESP) for the proposed IGCC and IRCC plants is 4.40 p/kWh and 4.10 p/kWh respectively, while for the conventional plant amounts to 4.73 p/kWh. A sensitivity analysis has been carried out by varying the most influential investment parameters. The analysis has revealed that, considering the uncertainties associated with these key parameters, a substantial risk that the BESP could exceed the first value obtained is so prominent in some cases to alter their ranking order with respect to the most competitive technology. The final part of the analysis is a Monte-Carlo simulation to determine the impact of simultaneous variations of all the variables, subject to uncertainty, on the break-even selling unit price for the generated electricity. From the simulation, it derives that the BESP value ranges from 3.13 p/kWh to over 6.00 p/kWh for the IGCC case with a 50% probability of exceeding the first value obtained (4.40 p/kWh). In the IRCC case, the range of possible value for the BESP is from 2.85 p/kWh to 6.10 p/kWh, and there is a 60% probability that the actual BESP would exceed the first value obtained (4.10 p/kWh). Copyright © 2013 John Wiley & Sons, Ltd.

A technical and economic analysis of three large scale biomass combustion plants in the UK

In the past there have been several reasons for not fuelling large scale power plants with biomass instead of fossil fuels. For example, fossil fuels have higher energy density, their costs had been relatively low until recently, the required (large) amounts of biomass have not been readily available and the cost and environmental impact of road transportation of large quantities of biomass were considerable. However, the impending scarcity of fossil fuels and their increased price, as well as environmental concerns, have led to renewed interest in the use of biomass for power generation. Many power plant operators have been encouraged by subventions to test cofiring of biomass with coal, which has often proved lucrative with little reduction in generation efficiency or significant impact on capital cost, and this, in turn, has increased familiarity with the characteristics of biomass, its handling, diminution, drying, storage and use at power plants and the details of its supply chain.One example of this increase in interest in biomass is the 350MWe CFBC power plant at Port Talbot in Wales. Two other examples are the medium scale biomass power plants, (a) the 44MWe Bubbling Fluidised Bed system at Steven’s Croft, Lockerbie in Scotland and (b) the 30MWe BFBC at Wilton (Wilton 10) in England.The technical, environmental and economic analysis of such technologies, using the ECLIPSE suite of process simulation software, is the subject of this study. The models are based on publicly-available data from the previously mentioned plants, but are not intended to replicate all aspects of them. System efficiencies for generating electricity and CO2 emissions are evaluated and compared with a large coal-fired CFBC plant and a typical supercritical coal-fired PF power plant.The specific investment (SI) and Break-Even Electricity Selling Price (BESP) for each system were calculated and compared with the coal-fired plants. The sensitivity of the economics of these large power plants to such factors as fuel cost, load factor and insurance, operational and maintenance costs for two discount cash flow rates was investigated. The BESP for the three biomass plants modelled were found to be competitive with the coal-fired plants at low wood costs, even without any subventions. The effect of applying the Renewable Obligations Certificate (ROC) subvention to the economics of the power plants was also assessed for a wide range of wood fuel costs.

Techno-economic assessment of biofuel development by anaerobic digestion of European marine cold-water seaweeds

The techno-economic characteristics of macro-algae utilisation from European temperate zones was evaluated in a selected Anaerobic Digester (AD) using the chemical process modelling software ECLIPSE. The assessment covered the mass and energy balance of the entire process followed by the economic feasibility study, which included the total cost estimation, net present value calculation, and sensitivity analysis. The selected plant size corresponded to a community based AD of 1.6MWth with a macro-algae feed rate of 8.64tonnes per day (dry basis). The produced biogas was utilised in a combined heat and power plant generating 237kWenet electricity and 367kWth heat. The breakeven electricity-selling price in this study was estimated at around €120/MWh. On the ground of different national and regional policies, this study did not account for any government incentives. However, different support mechanisms such as Feed-in-Tariffs or Renewable Obligation Certificates can significantly improve the project viability.

A techno-economic assessment of biomass fuelled trigeneration system integrated with organic Rankine cycle

Biomass fuelled trigeneration is the term given to the system which is the on-site generation of electricity, heat and cooling simultaneously, using biomass as the fuel source. As a form of the renewable energy sources biomass is not intermittent, location-dependent or very difficult to store. If grown sustainably, biomass can be considered to be CO2 neutral. Biomass, therefore, would be a promising option for the future to contribute both to the reduction of greenhouse gases and to the solution of replacing fossil fuels in power plants. For a wide range of commercial buildings, biomass trigeneration offers an economical solution of providing power, heat and cooling which is more environmentally friendly than conventional methods.This work focuses on the modelling, simulation and techno-economic analysis of small scale biomass trigeneration applications. The Organic Rankine Cycle (ORC) integrated with conventional combustion provides electricity for building use. The waste heat recovered from the ORC system and exhaust gases is used to supply hot water to space heating and excess heat is also used to drive an absorption cooling system. In order to use energy resources most efficiently, the proposed process is modelled and simulated using the ECLIPSE process simulation package. Based on the results achieved, the key technical and environmental issues have been examined. The study also investigates the impact of different biomass feedstock on the performance of trigeneration plant, biomass ash content ranges from 0.57 to 14.26% ash and a range of moisture content 10.6–33.51%. The calorific value across the biomass sources ranges between 16.56 and 17.97MJ/kg daf. Finally, an economic evaluation of the system is performed along with sensitivity analyses such as capital investments, plant load factors and fuel costs. The results show that the maximum efficiencies and the best breakeven electricity selling price for the cases considered in this study are as follows: 11.1% and 221 £/MWh for power only, 85.0% and 87 £/MWh for combined heat and power and 71.7% and 103 £/kWh for trigeneration respectively.

A Techno-economic assessment of the reduction of carbon dioxide emissions through the use of biomass co-combustion

Using sustainably-grown biomass as the sole fuel, or co-fired with coal, is an effective way of reducing the net CO 2 emissions from a combustion power plant. There may be a reduction in efficiency from the use of biomass, mainly as a result of its relatively high moisture content, and the system economics may also be adversely affected. The economic cost of reducing CO 2 emissions through the replacement of coal with biomass can be identified by analysing the system when fuelled solely by biomass, solely by coal and when a coal-biomass mixture is used. The technical feasibility of burning biomass or certain wastes with pulverised coal in utility boilers has been well established. Cofiring had also been found to have little effect on efficiency or flame stability, and pilot plant studies had shown that cofiring could reduce NO x and SO x emissions. Several technologies could be applied to the co-combustion of biomass or waste and coal. The assessment studies here examine the potential for co-combustion of (a) a 600 MWe pulverised fuel (PF) power plant, (i) cofiring coal with straw and sewage sludge and (ii) using straw derived fuel gas as return fuel; (b) a 350 MWe pressurised fluidised bed combustion (PFBC) system cofiring coal with sewage sludge; (c) 250 and 125 MWe circulating fluidised bed combustion (CFBC) plants cofiring coal with straw and sewage sludge; (d) 25 MWe CFBC systems cofiring low and high sulphur content coal with straw, wood and woody matter pressed from olive stones (WPOS); and (e) 12 MWe CFBC cofiring low and high sulphur content coal with straw. The technical, environmental and economic analysis of such technologies, using the ECLIPSE suite of process simulation software, is the subject of this study. System efficiencies for generating electricity are evaluated and compared for the different technologies and system scales. The capital costs of systems are estimated for coal-firing and also any additional costs introduced when biomass is used. The Break-even electricity selling price is calculated for each technology, taking into account the system scale and fuel used. Since net CO 2 emissions are reduced when biomass is used, the effect of the use of biomass on the electricity selling price can be found and the premium required for emissions reduction assessed. Consideration is also given to the level of subvention required, either as a Carbon dioxide Credit or as a Renewable Credit, to make the systems using biomass competitive with those fuelled only with coal. It would appear that a Renewable Credit (RC) is a more transparent and cost-effective mechanism to support the use of biomass in such power plants than a Carbon dioxide Credit (CC).

Natural gas oxy-fuel cycles—Part 3: Economic evaluation

As part of the sixth European framework project on enhanced capture of CO2 (ENCAP), several novel power generation cycles with CO2 pre-capture methods are identified and the promising technologies are selected for a techno-economic assessment. For this analysis, the chemical process simulation package ECLIPSE is utilised. Following a detailed mass and energy balance calculation, the economic assessments of the Semi-close Oxygen Combustion (SCOC), Water Cycle and Graz as well as S-Graz Cycles is performed in reference to year 2004. The total capital cost estimation of the studied cycles is implemented in a bottom-up approach. Subsequently, the breakeven electricity selling price (BESP) is determined according to the net present value. Through the modification of parameters such as fuel price or capacity factor, the sensitivity analysis is carried out to assess the effect of endogenous or exogenous changes on the economic viability of the cycles. Among the systems, the S-Graz Cycle is the most cost intensive process. Yet, due to its high plant efficiency, it delivers the lowest electricity price and the lowest CO2-avoidance costs. The Water Cycle is the least capital intensive technology in this study. Due to its poorer plant efficiency however, the economics of this cycle scored third on the list.

Power generation from biomass in a small CFBC plant compared with biomass co-fired with coal in a large CFBC

SYNOPSIS Biomass is one of the renewable energy sources which is not intermittent, location-dependent or very difficult to store. If grown sustainably, biomass can be considered to be CO2 neutral. The use of biomass for power generation is also considered to be important in increasing the electricity output from renewable energy sources. However, power plants dedicated to the use of biomass fuel are not in widespread use and the acceptance of this fuel and development of the infrastructure for biomass production and transportation remain in their infancy. If small ratios of biomass can be co-fired with coal in large-scale conventional power plants, without significant technical, environmental or economic penalties, it could lead to a greater demand for biomass and so stimulate the industry. In this study a 80 MWth Circulating Fluidised Bed Combustion (CFBC) plant, fuelled by biomass only, and a large-scale 1000 MWth CFBC, co-fired with coal and 8% biomass, and the same large CFBC system, fired only with coal, are modelled using the ECLIPSE process simulation package and their technical, environmental and economic properties analysed and compared. The co-firing of biomass with coal was found to have little effect on the large-scale CFBC system, when a small ratio of biomass is used. The large scale system was found to have higher efficiency, lower CO2 emissions and lower breakeven electricity selling price than the small biomass-fuelled CFBC. Co-firing of biomass with coal could be a promising way of promoting the production, use and acceptance of biomass as a fuel in electricity generation.

Absorption enhanced reforming of lignite integrated with molten carbonate fuel cell

A technical-economic assessment of an innovative system which integrates absorption enhanced reforming (AER) of lignite with molten carbonate fuel cell (MCFC) for electricity generation is investigated using the ECLIPSE process simulator. The simulation results show that the proposed system of combining AER with MCFC has the electricity output of 206 kW, with the electrical efficiency of 44.7% (low heating value – LHV) and CO 2 emissions of 751 g/kW h, when fuelled with lignite. The system has a specific investment (SI) of £11 642 and a break even electricity selling price (BESP) 21 p/kW e, compared to the SI of £10 477 and the BESP of 19 p/kW e for the basic case of MCFC fuelled with natural gas. A sensitivity analysis of the break even selling price (BESP) of electricity and the specific investment (SI) versus the capital cost show that capital costs have a significant effect on BESP and SI. Based on the basic case of capital cost of £2 398 000, when the capital cost of the system reduces 50%, the relevant BESP lowers down to 10.8 p/kW e, the SI also reduces by 50%, to £5864/kW e. A sensitivity analysis of fuel cost versus BESP show that the fuel cost has a little effect on BESP. For the basic case of the system with the cost of lignite £20/ton, the BESP is 21.1 p/kW e. While the fuel cost reduces by 50%, to £10/ton, the BESP lower down to 20.9 p/kW e, only reduces 0.2 p/kW e, the change is 0.9%. Although the BESP and SI are high for the AER + MCFC system, there are no nitrogen oxides (NO x ) and sulphur oxides (SO x ) emissions from the system; the CO 2 gas stream produced in the AER process is suitable for subsequent sequestration. Thus the combination system may become a power generation with zero greenhouse gas emissions.

Performance simulation of an absorption heat transformer operating with partially miscible mixtures : Alonso, D. et al. Applied Energy, 2002, 72, (3–4), 583–597

Using sustainably-grown biomass as the sole fuel, or co-fired with coal, is an effective way of reducing the net CO2 emissions from a combustion power plant. There may be a reduction in efficiency from the use of biomass, mainly as a result of its relatively high moisture content, and the system economics may also be adversely affected.The economic cost of reducing CO2 emissions through the replacement of coal with biomass can be identified by analysing the system when fuelled solely by biomass, solely by coal and when a coal-biomass mixture is used.The technical feasibility of burning biomass or certain wastes with pulverised coal in utility boilers has been well established. Cofiring had also been found to have little effect on efficiency or flame stability, and pilot plant studies had shown that cofiring could reduce NOx and SOx emissions.Several technologies could be applied to the co-combustion of biomass or waste and coal. The assessment studies here examine the potential for co-combustion of (a) a 600 MWe pulverised fuel (PF) power plant, (i) cofiring coal with straw and sewage sludge and (ii) using straw derived fuel gas as return fuel; (b) a 350 MWe pressurised fluidised bed combustion (PFBC) system cofiring coal with sewage sludge; (c) 250 and 125 MWe circulating fluidised bed combustion (CFBC) plants cofiring coal with straw and sewage sludge; (d) 25 MWe CFBC systems cofiring low and high sulphur content coal with straw, wood and woody matter pressed from olive stones (WPOS); and (e) 12 MWe CFBC cofiring low and high sulphur content coal with straw.The technical, environmental and economic analysis of such technologies, using the ECLIPSE suite of process simulation software, is the subject of this study. System efficiencies for generating electricity are evaluated and compared for the different technologies and system scales. The capital costs of systems are estimated for coal-firing and also any additional costs introduced when biomass is used. The Break-even electricity selling price is calculated for each technology, taking into account the system scale and fuel used.Since net CO2 emissions are reduced when biomass is used, the effect of the use of biomass on the electricity selling price can be found and the premium required for emissions reduction assessed. Consideration is also given to the level of subvention required, either as a Carbon dioxide Credit or as a Renewable Credit, to make the systems using biomass competitive with those fuelled only with coal.It would appear that a Renewable Credit (RC) is a more transparent and cost-effective mechanism to support the use of biomass in such power plants than a Carbon dioxide Credit (CC).

Clean power generation from coal

Studies conducted at the Energy Research Centre at the University of Ulster, Coleraine have been made using an ECLIPSE process simulator to perform technical and economic analysis of a number of coal-fired power generation technologies, including an analysis of the effect of a carbon tax on the relative economics of these processes. They have also examined the impact on these technologies of installing equipment for sequestering CO 2 and using the CO 2 produced in enhanced oil recovery. The results show that advanced coal-fired power generation systems provide a means of reducing CO 2 emissions through improved conversion efficiency without adversely affecting electricity selling prices. A carbon tax of £32/tonne CO 2 would increase the breakeven electricity selling price by about 65%–75%, but even at this high level a carbon tax does not provide any real incentive to develop these advanced coal-fired power generation systems. Selling liquid CO 2 for use in enhanced oil recovery is potentially attractive for all coal-fired power generation technologies.

Clean power generation from coal

Abstract Studies conducted at the Energy Research Centre at the University of Ulster, Coleraine have been made using an ECLIPSE process simulator to perform technical and economic analysis of a number of coal-fired power generation technologies, including an analysis of the effect of a carbon tax on the relative economics of these processes. They have also examined the impact on these technologies of installing equipment for sequestering CO 2 and using the CO 2 produced in enhanced oil recovery. The results show that advanced coal-fired power generation systems provide a means of reducing CO 2 emissions through improved conversion efficiency without adversely affecting electricity selling prices. A carbon tax of £32/tonne CO 2 would increase the breakeven electricity selling price by about 65%–75%, but even at this high level a carbon tax does not provide any real incentive to develop these advanced coal-fired power generation systems. Selling liquid CO 2 for use in enhanced oil recovery is potentially attractive for all coal-fired power generation technologies.