Modelling the competitiveness of first generation commercial OTEC power plants

First generation OTEC plants are expected to be used mainly for baseload electricity generation in the United States Gulf Coast region. In this application, OTEC plants would compete directly with nuclear and coal-fired power plants. The prospective competitiveness of OTEC is evaluated by comparing the delivered cost of electricity generated by the three types of plant for a geographical scenario typical of the region. The comparison is carried out using a modified version of the cost of energy model developed by the Jet Propulsion Laboratory and current estimates of future construction, operating and maintenance costs for the three power plant types. Four main independent variables are considered in this study: OTEC plant capital costs, real fuel escalation rates, real cost of capital resources, and OTEC plant operating capacity factors. The first two factors are found to be prime determinants of OTEC competitiveness. The values commonly forecasted suggest that OTEC plants are likely to deliver electricity at roughly the same cost as nuclear and coal-fired power plants by the year 2000. By contrast, variations in the real cost of capital resources and in OTEC plant capacity factors are found to have only a minor impact on the competitiveness of OTEC with conventional modes of electricity generation.     

Does regulation stimulate productivity? The effect of air quality policies on the efficiency of US power plants

This research examines the effect of air quality regulations on the productivity of US power plants based on both economic and environmental outputs. Using data envelopment analysis (DEA) to estimate an efficiency measure incorporating both economic and environmental outcomes, we look at changes in efficiency in US power plants over an eleven-year time period (1994–2004) during which several different regulations were implemented for the control of nitrogen oxides (NO_x) and sulfur dioxide (SO₂). The paper then models how estimated efficiency behaves over time as a function of regulatory changes. Findings suggest mixed effects of regulations on power plant efficiency when pollution abatement and electricity generation are both included as outputs.     

几种类型发电公司环境成本核算的分析研究

在自由的电力市场条件下，发电厂的环境成本将会被纳入发电成本，成为影响市场竞争力的重要因素。为了比较不同电源的环境成本对电价的影响程度，应用环境经济学理论分别对燃煤发电、天然气发电以及核能发电的环境成本进行了核算和比较。     

Power generation potential of liquified natural gas regasification terminals

The share of liquified natural gas (LNG) in the international trade of natural gas (NG) is continually increasing. This presents increasing opportunities to build power plants to generate electricity at LNG regasification terminals rather than wasting the power generation potential of LNG at about −162°C by regasifying it by seawater, ambient air, or by burning NG. Typically, over 5% of the NG received at LNG plants is used to liquify the remaining incoming gaseous NG at environmental conditions. Theoretically, all the energy consumed at LNG liquefaction plants can be recovered at LNG regasification terminals. In this study, the theoretical and practical power generation potential of regasified LNG is investigated by performing energy and exergy analyses. It is shown that up to 0.191 kWh of electric power can be generated during the regasification of LNG per standard m³ of NG regasified. The potential economic gains associated with power generation at LNG regasification facilities are demonstrated by analyzing the 2018 LNG imports of Turkey as a case study and the world. It is shown that the 314 million tons of LNG imported globally in 2018 has the electric power generation potential of 88 billion kWh with a market value of over 10 billion USD. It also has the potential to offset 38 million tons of CO₂ emissions.     

电力供应社会成本分析

市场经济条件下,发电成本一直使用生产成本来衡量,没有考虑环境因素的影响,本文综合电力供应经济性和对环境的影响程度,提出发电社会成本概念。主要对燃煤发电、风力发电、天然气发电和生物质发电进行社会成本分析。首先采用动态分析法中的费用年值法对发电生产成本进行估算;然后提出依据环境价值标准来估算发电环境成本;最后综合分析四种发电方式社会成本,提出我国电源结构发展趋势。     

Short-term impact of green certificates and CO2 emissions trading in the Swedish district heating sector

Swedish district-heating (DH) systems use a wide range of energy sources and technologies for heat-and-power generation. This provides the DH utilities with major flexibility in changing their fuel and technology mix when the economic conditions for generation change. Two recently introduced policy instruments have changed the DH utilities’ costs for generation considerably; the tradable green-certificate (TGC) scheme introduced in 2003 in Sweden, and the tradable greenhouse-gas emission permit (TEP) scheme introduced in the EU on January 1, 2005. The objective of this study is to analyse how these two trading schemes impact on the operation of the Swedish DH sector in terms of changes in CHP generation, CO₂ emissions, and operating costs. The analysis was carried out by comparing the most cost-effective operation for the DH utilities, with and without, the two trading schemes applied, using a model that handles the Swedish DH-sector system-by-system. It was found that the volume of renewable power generated in CHP plants only increased slightly owing to the TGC scheme. The TGC and the TEP schemes in force together, however, nearly doubled the renewable power-generation. CO₂ emissions from the DH sector may either increase or decrease depending on the combination of TGC and TEP prices. The overall CO₂ emissions from the European power-generation sector would, however, be reduced for all price combinations assuming that increased Swedish CHP generation replaces coal-condensing power (coal-fired plants with power generation only) in other European countries. The trading schemes also lower the operational costs of the DH sector since the cost increase owing to the use of more expensive fuels and the purchase of TEPs is outweighed by the increased revenues from sales of electricity and TGCs.     

Life cycle assessment study of solar PV systems: An example of a 2.7 kWp distributed solar PV system in Singapore

In life cycle assessment (LCA) of solar PV systems, energy pay back time (EPBT) is the commonly used indicator to justify its primary energy use. However, EPBT is a function of competing energy sources with which electricity from solar PV is compared, and amount of electricity generated from the solar PV system which varies with local irradiation and ambient conditions. Therefore, it is more appropriate to use site-specific EPBT for major decision-making in power generation planning. LCA and life cycle cost analysis are performed for a distributed 2.7 kW_p grid-connected mono-crystalline solar PV system operating in Singapore. This paper presents various EPBT analyses of the solar PV system with reference to a fuel oil-fired steam turbine and their greenhouse gas (GHG) emissions and costs are also compared. The study reveals that GHG emission from electricity generation from the solar PV system is less than one-fourth that from an oil-fired steam turbine plant and one-half that from a gas-fired combined cycle plant. However, the cost of electricity is about five to seven times higher than that from the oil or gas fired power plant. The environmental uncertainties of the solar PV system are also critically reviewed and presented.     

High efficiency electric power generation: The environmental role

Electric power generation system development is reviewed with special attention to plant efficiency. It is generally understood that efficiency improvement that is consistent with high plant reliability and low cost of electricity is economically beneficial, but its effect upon reduction of all plant emissions without installation of additional environmental equipment, is less well appreciated. As CO₂ emission control is gaining increasing acceptance, efficiency improvement, as the only practical tool capable of reducing CO₂ emission from fossil fuel plant in the short term, has become a key concept for the choice of technology for new plant and upgrades of existing plant. Efficiency is also important for longer-term solutions of reducing CO₂ emission by carbon capture and sequestration (CCS); it is essential for the underlying plants to be highly efficient so as to mitigate the energy penalty of CCS technology application. Power generating options, including coal-fired Rankine cycle steam plants with advanced steam parameters, natural gas-fired gas turbine-steam, and coal gasification combined cycle plants are discussed and compared for their efficiency, cost and operational availability. Special attention is paid to the timeline of the various technologies for their development, demonstration and commercial availability for deployment.     

External costs from electricity generation of China up to 2030 in energy and abatement scenarios

This paper presents estimated external costs of electricity generation in China under different scenarios of long-term energy and environmental policies. Long-range Energy Alternatives Planning (LEAP) software is used to develop a simple model of electricity demand and to estimate gross electricity generation in China up to 2030 under these scenarios. Because external costs for unit of electricity from fossil fuel will vary in different government regulation periods, airborne pollutant external costs of SO₂, NO_x, PM₁₀, and CO₂ from fired power plants are then estimated based on emission inventories and environmental cost for unit of pollutants, while external costs of non-fossil power generation are evaluated with external cost for unit of electricity. The developed model is run to study the impact of different energy efficiency and environmental abatement policy initiatives that would reduce total energy requirement and also reduce external costs of electricity generation. It is shown that external costs of electricity generation may reduce 24–55% with three energy policies scenarios and may further reduce by 20.9–26.7% with two environmental policies scenarios. The total reduction of external costs may reach 58.2%.     

Internalisation of external cost in the power generation sector: Analysis with Global Multi-regional MARKAL model

The Global MARKAL-Model (GMM), a multi-regional “bottom-up” partial equilibrium model of the global energy system with endogenous technological learning, is used to address impacts of internalisation of external costs from power production. This modelling approach imposes additional charges on electricity generation, which reflect the costs of environmental and health damages from local pollutants (SO₂, NO_x) and climate change, wastes, occupational health, risk of accidents, noise and other burdens. Technologies allowing abatement of pollutants emitted from power plants are rapidly introduced into the energy system, for example, desulphurisation, NO_x removal, and CO₂ scrubbers. The modelling results indicate substantial changes in the electricity production system in favour of natural gas combined cycle, nuclear power and renewables induced by internalisation of external costs and also efficiency loss due to the use of scrubbers. Structural changes and fuel switching in the electricity sector result in significant reduction of emissions of both local pollution and CO₂ over the modelled time period. Strong decarbonisation impact of internalising local externalities suggests that ancillary benefits can be expected from policies directly addressing other issues then CO₂ mitigation. Finally, the detailed analysis of the total generation cost of different technologies points out that inclusion of external cost in the price of electricity increases competitiveness of non-fossil generation sources and fossil power plants with emission control.     

Economic implications of pre- and post-combustion calcium looping configurations applied to gasification power plants

Gasification is a promising conversion technology to deliver high energy efficiency simultaneously with low energy and cost penalties for carbon capture. This paper is devoted to in-depth economic evaluations of pre- and post-combustion Calcium Looping (CaL) configurations for Integrated Gasification Combined Cycle (IGCC) power plants. The poly-generation capability, e.g. hydrogen and power co-generation, is also discussed. The post-combustion CaL option is a gasification power plant in which the flue gases from the gas turbine are treated for CO₂ capture in a carbonation–calcination cycle. In pre-combustion CaL option, the Sorbent Enhanced Water Gas Shift (SEWGS) feature is used to produce hydrogen which is used for power generation. As benchmark case, a conventional gasification power plant without carbon capture was considered. Net power output of evaluated cases is in the range of 550–600 MW with more than 95% carbon capture rate. The pre-combustion capture configuration was evaluated also in hydrogen and power co-generation scenario. The evaluations are concentrated for estimation of capital costs, specific investment cost, operational & maintenance (O&M) costs, CO₂ removal and avoidance costs, electricity costs, sensitivity analysis of technical and economic assumptions on key economic indicators etc.     

Avoidance of partial load operation at coal-fired power plants by storing nuclear power through power to gas

The need of fast regulation of electricity production leads to a number of inconveniences occurred to the electric generation system and the electric market, especially to the nuclear power. A new concept to control nuclear power production is posed in order to allow the regulation of the electricity sent to the grid. This concept proposes the joint operation of a nuclear power plant, a coal power plant with postcombustion capture and a methanation plant. The cost effectiveness of this technology and its capability to reduce the CO₂ emissions -consumed in the methanation process- are assessed through the design and economic and environmental analysis of a hybrid facility. Mainly due to the increase of the operating hours of the coal-fired power plant, the environmental feasibility of the initial proposal seems to be limited. However, given that benefits are expected in the medium and long-term (2020–2030) for the Power to Gas facility, a future alternative use is proposed. The target of this new alternative configuration will be the storage of CO₂ together with the storage of renewable energy.     

Large-scale economic integration of electricity from short-rotation woody crops

This paper presents an assessment of the installation of a large-scale biomass scheme for production of electricity for distribution via the national grid in Spain. The biomass scheme studied is based on woody biomass (eucalyptus, acacia and poplar) as short rotation crops in arable lands. The site selection process has been carried out with a Geographical Information System (GIS). The criteria applied in the selection, cultivation and location of the plantation as well as the biomass power plants have taken into account environmental aspects and the economic costs, always pursuing the lowest energy cost and environmental impacts. The size of each power plant has been calculated taking into account the annual productivity of biomass and the available surface of arable non-irrigated land. The costs of energy crop production in each area have been calculated as well as the storage and transport costs to supply the power plants. The technologies considered for generating electricity are fluidized bed combustion (FBC) and biomass gasification integrated into a combined cycle (BIGCC). The costs of electricity, considering also the connection costs to the electricity grid, have been calculated for all power plants. Cost figures along the fuel cycle have been obtained and a sensitivity analysis of the most relevant variables has been made. The main conclusion of the analysis is that from an economic and environmental point of view, the scheme proposed is feasible.     

Application of cool storage air-conditioning in the commercial sector: an integrated resource planning approach for power capacity expansion planning and emission reduction

An assessment is presented of the evaluation of the application of cool storage air-conditioning (CSA) in the commercial sector as a resource in the electricity generation expansion planning. The resultant impacts of analysis of emission costs on annual emissions from power generation are also discussed. A building energy simulation tool is used for assessment of potential savings and peak load shifting of CSA application in commercial buildings. In this study, an integrated resource planning (IRP) model is used to evaluate the economic effectiveness of the CSA option. The IRP analysis with emission costs results in deferring the installation of four units of 1000-MW coal-fired power plant from 2010 to 2011, and one unit of 1000-MW coal-fired power plant and one 200-MW CSA option are removed from the IRP plan. Results show that the CSA option is a viable resource in the least-cost planning and reducing environmental emissions.     

Techno-economic assessment of fossil fuel power plants with CO2 capture – Results of EU H2-IGCC project

In order to address the ever-increasing demand for electricity, need for security of energy supply, and to stabilize global warming, the European Union co-funded the H₂-IGCC project, which aimed to develop and demonstrate technological solutions for future generation integrated gasification combined cycle (IGCC¹) plants with carbon capture. As a part of the main goal, this study evaluates the performance of the selected IGCC plant with CO₂ capture from a techno-economic perspective. In addition, a comparison of techno-economic performance between the IGCC plant and other dominant fossil-based power generation technologies, i.e. an advanced supercritical pulverized coal (SCPC²) and a natural gas combined cycle (NGCC³), have been performed and the results are presented and discussed here. Different plants are economically compared with each other using the cost of electricity and the cost of CO₂ avoided. Moreover, an economic sensitivity analysis of every plant considering the realistic variation of the most uncertain parameters is given.     

Estimating the health damage costs of syrian electricity generation system using impact pathway approach

Based on the simplified impact pathway approach the environmental impacts from airborne pollutant emissions of Syrian electricity generation system have been assessed and the associated external damage costs to human health have been evaluated. The obtained results indicate that the environmental impacts can add considerable external cost to the typical generation cost. The estimated externalities vary between 2.5 and 0.07 US-cents per generated kWh for heavy fuel oil and NG fired power plants respectively. For the fuel oil fired power plants the resulting external cost, arise mainly from Sulphates impact, amounts to about 25% of the present generation costs. These results indicate the advantage of NG fired power plants as clean generation technology and the necessity of supplying oil fired power plants with SO₂ emission reduction technologies.     

A liquefied energy chain for transport and utilization of natural gas for power production with CO2 capture and storage – Part 2: The offshore and the onshore processes

A novel energy and cost effective transport chain for stranded natural gas utilized for power production with CO₂ capture and storage is developed. It includes an offshore section, a combined gas carrier, and an integrated receiving terminal. In the offshore process, natural gas (NG) is liquefied to LNG by liquid carbon dioxide (LCO₂) and liquid inert nitrogen (LIN), which are used as cold carriers. The offshore process is self-supported with power, hot and cold utilities and can operate with little rotating equipment and without flammable refrigerants. In the onshore process, the cryogenic exergy in LNG is used to cool and liquefy the cold carriers, which reduces the power requirement to 319 kWh/tonne LNG. Pinch and exergy analyses are used to determine thermodynamically optimized offshore and onshore processes with exergy efficiencies of 87% and 71%, respectively. There are very low emissions from the processes. The estimated specific costs for the offshore and onshore process are 8.0 and 14.6 EUR per tonne LNG, respectively, excluding energy costs. With an electricity price of 100 EUR per MWh, the specific cost of energy in the onshore process is 31.9 EUR per tonne LNG.     

Assessment of operational and environmental performance of the thermal power plants in Turkey by using data envelopment analysis

In this study, efficiency analyses of the eleven lignite-fired, one hard coal-fired and three natural gas-fired state-owned thermal power plants used for electricity generation were conducted through data envelopment analysis (DEA). Two efficiency indexes, operational and environmental performance, were defined and pursued. In the calculation of the operational performance, main production indicators were used as input, and fuel cost per actual production (Y) was used as output (Model 1). On the other hand, in the calculation of the environmental performance, gases emitted to the environment were used as output (Model 2). Data envelopment analysis (DEA) is the main instrument for the measurement of relative performances of the decision making units with multiple inputs and outputs. Constant returns to scale (CRS or CCR) and variable returns to scale (VRS or BCC) type DEA models were used in the analyses. The relationship between efficiency scores and input/output factors was investigated. Employing the obtained results, the power plants were evaluated with respect to both the cost of electricity generation and the environmental effects.     

Historical costs of coal-fired electricity and implications for the future

We study the cost of coal-fired electricity in the United States between 1882 and 2006 by decomposing it in terms of the price of coal, transportation cost, energy density, thermal efficiency, plant construction cost, interest rate, capacity factor, and operations and maintenance cost. The dominant determinants of cost have been the price of coal and plant construction cost. The price of coal appears to fluctuate more or less randomly while the construction cost follows long-term trends, decreasing from 1902 to 1970, increasing from 1970 to 1990, and leveling off since then. Our analysis emphasizes the importance of using long time series and comparing electricity generation technologies using decomposed total costs, rather than costs of single components like capital. By taking this approach we find that the history of coal-fired electricity suggests there is a fluctuating floor to its future costs, which is determined by coal prices. Even if construction costs resumed a decreasing trend, the cost of coal-based electricity would drop for a while but eventually be determined by the price of coal, which fluctuates while showing no long-term trend.     

Analysis of MTH-System (Methylcyclohexane-Toluene-Hydrogen-System) for hydrogen production as fuel for power plants

The utilization of hydrogen (H₂) gas as green energy fuel in power plants is a great challenge due to its storage, deployment and transportation. Herein, we propose a simulation based study of H₂ fueled power plant by using Methylcyclohexane-Toluene-Hydrogen-System (MTH-System). A 266 MW gas turbine was selected and the performance of MTH-System for power plant was investigated. The process for methylcyclohexane (MCH) production was not discussed here. However, the conversion of MCH into gaseous H₂ for power generation was discussed in detail. A sustainable process flow diagram (PFD) was developed. The heat integration b/w power plant and dehydrogenation reactor reveal that, minimum 70% MCH conversion is required to accomplish the heat demand of whole system. The effect of addition of H₂ recycle stream to dehydrogenation reactor and combined cycle power plants was investigated. The sensitivity and economic analysis reveal 2291.4 $/kW capital cost based on dehydrogenation of MCH for power production and 0.186 $/kWh output electricity cost based on complete MTH-System.