A long-term view of fossil-fuelled power generation in Europe

The paper presents a view into the long term future of fossil-fuelled power generation in the European Union, based on a number of alternative scenarios for the development of the coal, natural gas and CO₂ markets, and the penetration of renewable and nuclear technologies. The new fossil fuelled capacity needed and the likely technology mix are estimated using a cost optimisation model based on the screening curve method, taking into consideration the rate of retirement of the current power plant fleet, the capacity already planned or under construction and the role of carbon capture and storage technologies. This analysis shows that measures to increase both non-fossil-fuel-based power generation and the price of CO₂ are necessary to drive the composition of the European power generation capacity so that the European policy goal of reducing greenhouse gas emissions is achieved. Meeting this goal will however require a high capital investment for the creation of an optimal fossil fuel power plant technology mix.     

Thermoeconomic analysis of pressurized hybrid SOFC systems with CO2 separation

In this paper, the results of the thermodynamic and economic analyses of distributed power generation plants (1.5 MWe) are described and compared. The results of an exergetic analysis are also reported, as well as the thermodynamic details of the most significant streams of the plants. The integration of different hybrid solid oxide fuel cell (SOFC) system CO₂ separation technologies characterizes the power plants proposed. A hybrid system with a tubular SOFC fed with natural gas with internal reforming has been taken as reference plant. Two different technologies have been considered for the same base system to obtain a low CO₂ emission plant. The first technology involved a fuel decarbonization and CO₂ separation process placed before the system feed, while the second integrated the CO₂ separation and the energy cycle. The first option employed fuel processing, a technology (amine chemical absorption) viable for short-term implementation in real installations while the second option provided the CO₂ separation by condensing the steam from the system exhaust. The results obtained, using a Web-based Thermo Economic Modular Program software, developed by the Thermochemical Power Group of the University of Genoa, showed that the thermodynamic and economic impact of the adoption of zero emission cycle layouts based on hybrid systems was relevant.     

The environmental impact and risk assessment of CO2 capture, transport and storage - An evaluation of the knowledge base

In this study, we identify and characterize known and new environmental consequences associated with CO₂ capture from power plants, transport by pipeline and storage in geological formations. We have reviewed (analogous) environmental impact assessment procedures and scientific literature on carbon capture and storage (CCS) options. Analogues include the construction of new power plants, transport of natural gas by pipelines, underground natural gas storage (UGS), natural gas production and enhanced oil recovery (EOR) projects. It is investigated whether crucial knowledge on environmental impacts is lacking that may postpone the implementation of CCS projects. This review shows that the capture of CO₂ from power plants results in a change in the environmental profile of the power plant. This change encompasses both increase and reduction of key atmospheric emissions, being: NO_x, SO₂, NH₃, particulate matter, Hg, HF and HCl. The largest trade-offs are found for the emission of NO_x and NH₃ when equipping power plants with post-combustion capture. Synergy is expected for SO₂ emissions, which are low for all power plants with CO₂ capture. An increase in water consumption ranging between 32% and 93% and an increase in waste and by-product creation with tens of kilotonnes annually is expected for a large-scale power plant (1 GW_e), but exact flows and composition are uncertain. The cross-media effects of CO₂ capture are found to be uncertain and to a large extent not quantified. For the assessment of the safety of CO₂ transport by pipeline at high pressure an important knowledge gap is the absence of validated release and dispersion models for CO₂ releases. We also highlight factors that result in some (not major) uncertainties when estimating the failure rates for CO₂ pipelines. Furthermore, uniform CO₂ exposure thresholds, detailed dose-response models and specific CO₂ pipeline regulation are absent. Most gaps in environmental information regarding the CCS chain are identified and characterized for the risk assessment of the underground, non-engineered, part of the storage activity. This uncertainty is considered to be larger for aquifers than for hydrocarbon reservoirs. Failure rates are found to be heavily based on expert opinions and the dose-response models for ecosystems or target species are not yet developed. Integration and validation of various sub-models describing fate and transport of CO₂ in various compartments of the geosphere is at an infant stage. In conclusion, it is not possible to execute a quantitative risk assessment for the non-engineered part of the storage activity with high confidence.     

Cycle analysis of low and high H2 utilization SOFC/gas turbine combined cycle for CO2 recovery

A major factor in global warming is CO₂ emission from thermal power plants, which burn fossil fuels. One technology proposed to prevent global warming is CO₂ recovery from combustion flue gas and the sequestration of CO₂ underground or near the ocean bed. Solid oxide fuel cell (SOFC) can produce highly concentrated CO₂, because the reformed fuel gas reacts with oxygen electrochemically without being mixed with air in the SOFC. We therefore propose to operate multi-staged SOFCs with high utilization of reformed fuel to obtain highly concentrated CO₂. In this study, we estimated the performance of multi-staged SOFCs considering H₂ diffusion and the combined cycle efficiency of a multi-staged SOFC/gas turbine/CO₂ recovery power plant. The power generation efficiency of our CO₂ recovery combined cycle is 68.5%, whereas the efficiency of a conventional SOFC/GT cycle with the CO₂ recovery amine process is 57.8%.     

Production of hydrogen-rich fuels for pre-combustion carbon capture in power plants: A thermodynamic assessment

Hydrogen-fueled plants can play an important role in the field of carbon capture and storage, because they facilitate the mitigation of harmful emissions. In this paper, two combined-cycle power plants with pre-combustion CO₂ capture are examined, in which natural gas is converted into a hydrogen-rich fuel through reforming. The first plant considered operates with a hydrogen-separating membrane and the second with an autothermal reformer. The two plants are compared to a reference plant without CO₂ capture and briefly to alternative oxy-fuel and post-combustion capture technologies. It is found that both plants suffer high penalties caused by the high energy requirements of the reforming components and the CO₂ compression units. Additionally, both plants appear inferior to alternative capture technologies. When comparing the two reforming plants, the plant with the hydrogen-separating membrane operates somewhat more efficiently. However, in order to make these technologies more attractive, their thermodynamic efficiency must be enhanced. The potential for improving the efficiencies of these plants is revealed by an exergetic analysis.     

MCFC-based CO2 capture system for small scale CHP plants

Carbon dioxide emissions into the atmosphere are considered among the main reasons of the greenhouse effect. The largest share of CO₂ is emitted by power plants using fossil fuels. Nowadays there are several technologies to capture CO₂ from power plants' exhaust gas but each of them consumes a significant part of the electric power generated by the plant. The Molten Carbonate Fuel Cell (MCFC) can be used as concentrator of CO₂, due to the chemical reactions that occurs in the cell stack: carbon dioxide entering into the cathode side is transported to the anode side via CO₃⁼ ions and is finally concentrated in the anodic exhaust. MCFC systems can be integrated in existing power plants (retro fitting) to separate CO₂ in the exhaust gas and, at the same time, produce additional energy. The aim of this study is to find a feasible system design for medium scale cogeneration plants which are not considered economically and technically interesting for existing technologies for carbon capture, but are increasing in numbers with respect to large size power plants. This trend, if confirmed, will increase number of medium cogeneration plants with consequent benefit for both MCFC market for this application and effect on global CO₂ emissions. System concept has been developed in a numerical model, using AspenTech engineering software. The model simulates a plant, which separates CO₂ from a cogeneration plant exhaust gases and produces electric power. Data showing the effect of CO₂ on cell voltage and cogenerator exhaust gas composition were taken from experimental activities in the fuel cell laboratory of the University of Perugia, FCLab, and from existing CHP plants. The innovative aspect of this model is the introduction of recirculation to optimize the performance of the MCFC. Cathode recirculation allows to decrease the carbon dioxide utilization factor of the cell keeping at the same time system CO₂ removal efficiency at high level. At anode side, recirculation is used to reduce the fuel consumption (due to the unreacted hydrogen) and to increase the CO₂ purity in the stored gas. The system design was completely introduced in the model and several analyses were performed. CO₂ removal efficiency of 63% was reached with correspondent total efficiency of about 35%. System outlet is also thermal power, due to the high temperature of cathode exhaust off gases, and it is possible to consider integration of this outlet with the cogeneration system. This system, compared to other post-combustion CO₂ removal technologies, does not consume energy, but produces additional electrical and thermal power with a global efficiency of about 70%.     

Cost and performance of fossil fuel power plants with CO2 capture and storage

CO₂ capture and storage (CCS) is receiving considerable attention as a potential greenhouse gas (GHG) mitigation option for fossil fuel power plants. Cost and performance estimates for CCS are critical factors in energy and policy analysis. CCS cost studies necessarily employ a host of technical and economic assumptions that can dramatically affect results. Thus, particular studies often are of limited value to analysts, researchers, and industry personnel seeking results for alternative cases. In this paper, we use a generalized modeling tool to estimate and compare the emissions, efficiency, resource requirements and current costs of fossil fuel power plants with CCS on a systematic basis. This plant-level analysis explores a broader range of key assumptions than found in recent studies we reviewed for three major plant types: pulverized coal (PC) plants, natural gas combined cycle (NGCC) plants, and integrated gasification combined cycle (IGCC) systems using coal. In particular, we examine the effects of recent increases in capital costs and natural gas prices, as well as effects of differential plant utilization rates, IGCC financing and operating assumptions, variations in plant size, and differences in fuel quality, including bituminous, sub-bituminous and lignite coals. Our results show higher power plant and CCS costs than prior studies as a consequence of recent escalations in capital and operating costs. The broader range of cases also reveals differences not previously reported in the relative costs of PC, NGCC and IGCC plants with and without CCS. While CCS can significantly reduce power plant emissions of CO₂ (typically by 85–90%), the impacts of CCS energy requirements on plant-level resource requirements and multi-media environmental emissions also are found to be significant, with increases of approximately 15–30% for current CCS systems. To characterize such impacts, an alternative definition of the “energy penalty” is proposed in lieu of the prevailing use of this term.     

The economic feasibility study of a 100-MW Power-to-Gas plant

Power-to-Gas (PtG) is a grid-scale energy storage technology by which electricity is converted into gas fuel as an energy carrier. PtG utilizes surplus renewable electricity to generate hydrogen from Solid-Oxide-Cell, and the hydrogen is then combined with CO₂ in the Sabatier process to produce the methane. The transportation of methane is mature and energy-efficient within the existing natural gas pipeline or town gas network. Additionally, it is ideal to make use of the reverse function of SOC, the Solid-Oxide-Fuel-Cell, to generate electricity when the grid is weak in power. This study estimated the cost of building a hypothetical 100-MW PtG power plant with energy storage and power generation capabilities. The emphasis is on the effects of SOC cost, fuel cost and capacity factor to the Levelized Cost of Energy of the PtG plant. The net present value of the plant is analyzed to estimate the lowest affordable contract price to secure a positive present value. Besides, the plant payback period and CO₂ emission are estimated.     

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.     

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.     

Capturing CO2 in flue gas from fossil fuel-fired power plants using dry regenerable alkali metal-based sorbent

CO₂ capture and storage (CCS) has received significant attention recently and is recognized as an important option for reducing CO₂ emissions from fossil fuel combustion. A particularly promising option involves the use of dry alkali metal-based sorbents to capture CO₂ from flue gas. Here, alkali metal carbonates are used to capture CO₂ in the presence of H₂O to form either sodium or potassium bicarbonate at temperatures below 100 °C. A moderate temperature swing of 120–200 °C then causes the bicarbonate to decompose and release a mixture of CO₂/H₂O that can be converted into a “sequestration-ready” CO₂ stream by condensing the steam. This process can be readily used for retrofitting existing facilities and easily integrated with new power generation facilities. It is ideally suited for coal-fired power plants incorporating wet flue gas desulfurization, due to the associated cooling and saturation of the flue gas. It is expected to be both cost effective and energy efficient.     

Baseload electricity from wind via compressed air energy storage (CAES)

This study investigates two methods of transforming intermittent wind electricity into firm baseload capacity: (1) using electricity from natural gas combined-cycle (NGCC) power plants and (2) using electricity from compressed air energy storage (CAES) power plants. The two wind models are compared in terms of capital and electricity costs, CO₂ emissions, and fuel consumption rates. The findings indicate that the combination of wind and NGCC power plants is the lowest-cost method of transforming wind electricity into firm baseload capacity power supply at current natural gas prices (∼$6/GJ). However, the electricity supplied by wind and CAES power plants becomes economically competitive when the cost of natural gas for electric producers is $10.55/GJ or greater. In addition, the Wind-CAES system has the lowest CO₂ emissions (93% and 71% lower than pulverized coal power plants and Wind-NGCC, respectively) and the lowest fuel consumption rates (9 and 4 times lower than pulverized coal power plants and Wind-NGCC, respectively). As such, the large-scale introduction of Wind-CAES systems in the U.S. appears to be the prudent long-term choice once natural gas price volatility, costs, and climate impacts are all considered.     

Techno-economic assessment on the fuel flexibility of a commercial scale combined cycle gas turbine integrated with a CO2 capture plant

Post-combustion carbon capture is a valuable technology, capable of being deployed to meet global CO₂ emissions targets. The technology is mature and can be retrofitted easily with existing carbon emitting energy generation sources, such as natural gas combined cycles. This study investigates the effect of operating a natural gas combined cycle plant coupled with carbon capture and storage while using varying fuel compositions, with a strong focus on the influence of the CO₂ concentration in the fuel. The novelty of this study lies in exploring the technical and economic performance of the integrated system, whilst operating with different fuel compositions. The study reports the design of a natural gas combined cycle gas turbine and CO₂ capture plant (with 30 wt% monoethanolamine), which were modelled using the gCCS process modelling application. The fuel compositions analysed were varied, with focus on the CO₂ content increasing from 1% to 5%, 7.5% and 10%. The operation of the CO₂ capture plant is also investigated with focus on the CO₂ capture efficiency, specific reboiler duty and the flooding point. The economic analysis highlights the effect of the varying fuel compositions on the cost of electricity as well as the cost of CO₂ avoided. The study revealed that increased CO₂ concentrations in the fuel cause a decrease in the efficiency of the natural gas combined cycle gas turbine; however, rising the CO₂ concentration and flowrate of the flue gas improves the operation of the capture plant at the risk of an increase in the flooding velocity in the column. The economic analysis shows a slight increase in cost of electricity for fuels with higher CO₂ contents; however, the results also show a reduction in the cost of CO₂ avoided by larger margins.     

Status of thermal power generation in India—Perspectives on capacity,generation and carbon dioxide emissions

India’s reliance on fossil-fuel based electricity generation has aggravated the problem of high carbon dioxide (CO₂) emissions from combustion of fossil fuels, primarily coal, in the country’s energy sector. The objective of this paper is to analyze thermal power generation in India for a four-year period and determine the net generation from thermal power stations and the total and specific CO₂ emissions. The installed generating capacity, net generation and CO₂ emissions figures for the plants have been compared and large generators, large emitters, fuel types and also plant vintage have been identified. Specific emissions and dates of commissioning of plants have been taken into account for assessing whether specific plants need to be modernized. The focus is to find out areas and stations which are contributing more to the total emissions from all thermal power generating stations in the country and identify the overall trends that are emerging.     

Development of a scalable infrastructure model for planning electricity generation and CO2 mitigation strategies under mandated reduction of GHG emission

In a power-generation system, power plants as major CO₂ sources may be widely separated, so they must be connected into a comprehensive network to manage both electricity and CO₂ simultaneously and efficiently. In this study, a scalable infrastructure model is developed for planning electricity generation and CO₂ mitigation (EGCM) strategies under the mandated reduction of GHG emission. The EGCM infrastructure model is applied to case studies of Korean energy and CO₂ scenarios in 2020; these cases consider combinations of prices of carbon credit and total electricity demand fulfilled by combustion power plants. The results highlight the importance of systematic planning for a scalable infrastructure by examining the sensitivity of the EGCM infrastructure. The results will be useful both to help decision makers establish a power-generation plan, and to identify appropriate strategies to respond to climate change.     

Achieving 60% CO2 reductions within the UK energy system—Implications for the electricity generation sector

This paper explores how investment in the UK electricity generation sector can contribute to the UK goal of reducing CO₂ emissions with 60% by the year 2050 relative to the 1990 emissions. Considering likely development of the transportation sector and industry over the period, i.e. a continued demand growth and dependency on fossil fuels and electricity, the analysis shows that this implies CO₂ emission reductions of up to 90% by 2050 for the electricity sector. Emphasis is put on limitations imposed by the present system, described by a detailed database of existing power plants, together with meeting targets on renewable electricity generation (RES) including assumptions on gas acting as backup technology for intermittent RES. In particular, it is investigated to what extent new fossil fuelled and nuclear power is required to meet the year 2050 demand as specified by the Royal Commission on Environmental Pollution (RCEP). In addition, the number of sites required for centralized electricity generation (large power plants) is compared with the present number of sites. A simulation model was developed for the analysis. The model applies the UK national targets on RES, taken from Renewable Obligation (RO) for 2010 and 2020 and potentials given by RCEP for 2050, and assumed technical lifetimes of the power plants of the existing system and thus, links this system with targets for the years 2010, 2020 and 2050.     

Life cycle CO2 emissions from power generation using hydrogen energy carriers

Hydrogen energy carriers such as liquid hydrogen (LH₂), methylcyclohexane (MCH), and ammonia (NH₃) are promising energy vectors in the clean energy systems currently being developed. However, their effectiveness in mitigating environmental emissions must be assessed by life cycle analyses throughout the supply chain. In this study, while focusing on hydrogen energy carriers, life cycle inventory analyses were conducted to estimate CO₂ emissions from the following types of power generation plants in Japan: a hydrogen (H₂) mono-firing power plant using LH₂ or MCH that originated from overseas renewable electricity; and NH₃ co-firing with fossil fuel and NH₃ mono-firing power plants using hydrogen energy carriers that originated from overseas natural gas or renewable electricity. Parameters related to the supply chains were collected by literature surveys, and the Japanese life cycle inventory database was primarily used to calculate the emissions. From the results, CO₂ hotspots of the target supply chains and potential measures are identified that become necessary to establish low-carbon supply chains.     

Comparative studies of augmentation in combined cycle power plants

The attractive features of a combined cycle (CC) power plant are fuel flexibility, operational flexibility, higher efficiency and low emissions. The performance of five gas turbine‐steam turbine (GT‐ST) combined cycle power plants (four natural gas based plants and one biomass based plant) have been studied and the degree of augmentation has been compared. They are (i) combined cycle with natural gas (CC‐NG), (ii) combined cycle with water injection (CC‐WI), (iii) combined cycle with steam injection (CC‐SI), (iv) combined cycle with supplementary firing (CC‐SF) and (v) combined cycle with biomass gasification (CC‐BM). The plant performance and CO₂ emissions are compared with a change in compressor pressure ratio and gas turbine inlet temperature (GTIT). The optimum pressure ratio for compressor is selected from maximum efficiency condition. The specific power, thermal efficiency and CO₂ emissions of augmented power plants are compared with the CC‐NG power plant at the individual optimized pressure ratios in place of a common pressure ratio. The results show that the optimum pressure ratio is increased with water injection, steam injection, supplementary firing and biomass gasification. The specific power is increased in all the plants with a loss in thermal efficiency and rise in CO₂ emissions compared to CC‐NG plant. Copyright © 2013 John Wiley & Sons, Ltd.     

Long-term CO2 emissions reduction target and scenarios of power sector in Taiwan

This study analyses a series of carbon dioxide (CO₂) emissions abatement scenarios of the power sector in Taiwan according to the Sustainable Energy Policy Guidelines, which was released by Executive Yuan in June 2008. The MARKAL-MACRO energy model was adopted to evaluate economic impacts and optimal energy deployment for CO₂ emissions reduction scenarios. This study includes analyses of life extension of nuclear power plant, the construction of new nuclear power units, commercialized timing of fossil fuel power plants with CO₂ capture and storage (CCS) technology and two alternative flexible trajectories of CO₂ emissions constraints. The CO₂ emissions reduction target in reference reduction scenario is back to 70% of 2000 levels in 2050. The two alternative flexible scenarios, Rt4 and Rt5, are back to 70% of 2005 and 80% of 2005 levels in 2050. The results show that nuclear power plants and CCS technology will further lower the marginal cost of CO₂ emissions reduction. Gross domestic product (GDP) loss rate in reference reduction scenario is 16.9% in 2050, but 8.9% and 6.4% in Rt4 and Rt5, respectively. This study shows the economic impacts in achieving Taiwan's CO₂ emissions mitigation targets and reveals feasible CO₂ emissions reduction strategies for the power sector.     

Technical efficiency and CO2 reduction potentials — An analysis of the German electricity and heat generating sector

In this paper, we analyze the technical efficiency and CO₂ reduction potentials of German power and heat plants, using a non-parametric sequential Data Envelopment Analysis. We apply a metafrontier framework to evaluate plant-level efficiency in the transformation of inputs into desirable (energy) and undesirable (CO₂ emissions) outputs, taking into account different fossil fuel generation technologies. We use a unique data set of coal-, lignite-, gas- and biomass-fired power plants from 2003 through 2010 that provides an unbalanced panel of 1459 observations; the results are also checked against a balanced panel with a smaller number of observations. Although we find intra-group differences within energy generation technology, natural gas fired power plants clearly have the highest efficiency. Furthermore, the analysis points to significant savings potentials for CO₂ and fuel-input, and derives policy conclusions for the ongoing electricity sector reformation.