Determinants of the costs of carbon capture and sequestration for expanding electricity generation capacity

This study models the costs of electricity generation with carbon capture and sequestration (CCS), from generation at the power plant to carbon injection at the reservoir, examining the economic factors that affect technology choice and CCS costs at the individual plant level. The results suggest that natural gas and coal prices have profound impacts on the carbon price needed to induce CCS. To extend previous analyses we develop a "cost region" graph that models technology choice as a function of carbon and fuel prices. Generally, the least-cost technology at low carbon prices is pulverized coal, while intermediate carbon prices favor natural gas technologies and high carbon prices favor coal gasification with capture. However, the specific carbon prices at which these transitions occur is largely determined by the price of natural gas. For instance, the CCS-justifying carbon price ranges from $27/t CO₂ at high natural gas prices to $54/t CO₂ at low natural gas prices. This result has important implications for potential climate change legislation. The capital costs of the generation and CO₂ capture plant are also highly important, while pipeline distance and criteria pollutant control are less significant.     

On the off-design of a natural gas-fired combined cycle with CO2 capture

During the last 15 years cycles with CO₂ capture have been in focus, due to the growing concern over our climate. Often, a natural gas fired combined cycle with a chemical absorption plant for CO₂ capture from the flue gases have been used as a reference in comparisons between cycles. Neither the integration of the steam production for regeneration of amines in the combined cycle nor the off-design behaviour of such a plant has been extensively studied before.     

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.     

A cryogen‐based peak‐shaving technology: systematic approach and techno‐economic analysis

A peak‐shaving technology is recently proposed, which integrates peak‐electricity generation, cryogenic energy storage and CO₂ capture. In such a technology, off‐peak electricity is used to produce liquid nitrogen and oxygen in an air separation and liquefaction unit. At peak hours, natural gas (or alternative gases, e.g. from gasification of coal) is burned by oxygen from the air separation unit (oxy‐fuel combustion) to generate electricity. CO₂ produced is captured in the form of dry ice. Liquid nitrogen produced in the air separation plant not only serves as an energy storage medium but also supplies the low‐grade cold energy for CO₂ separation. In addition, waste heat from the tail gas can be used to superheat nitrogen in the expansion process to further increase the system efficiency. This article reports a systematic approach, with an aim to provide technical information for the system design. Three potential blending gases (helium, oxygen and CO₂) are considered not only for assessing thermodynamic performance but also for techno‐economic analysis. The peak‐shaving systems are also compared with natural gas combined cycle and an oxy–natural gas combined cycle in terms of capital cost and peak electricity production cost. Copyright © 2011 John Wiley & Sons, Ltd.     

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.     

Optimal greenhouse gas emissions in NGCC plants integrating life cycle assessment

The optimal design of an energy-intensive process involves a compromise between costs and greenhouse gas emissions, complicated by the interaction between optimal process emissions and supply chain emissions. We propose a method that combines generic abatement cost estimates and the results of existing (LCA) life cycle assessment studies, so that supply chain emissions are properly handled during optimization. This method is illustrated for a (NGCC) natural gas combined cycle power plant model with the following design and procurement options: procurement of natural gas from low-emissions producers, fuel substitution with (SNG) synthetic natural gas from wood, and variable-rate CO₂ capture and sequestration from both the NGCC and SNG plants. Using multi-objective optimization, we show two Pareto-optimal sets with and without the proposed LCA method. The latter can then be shown to misestimate CO₂ abatement costs by a few percent, penalizing alternate fuels and energy-efficient process configurations and leading to sub-optimal design decisions with potential net losses of the order of $1/MWh. Thus, the proposed LCA method can enhance the economic analysis of emissions abatement technologies and emissions legislation in general.     

Economic comparison between coal-fired and liquefied natural gas combined cycle power plants considering carbon tax: Korean case

Economic growth is main cause of environmental pollution and has been identified as a big threat to sustainable development. Considering the enormous role of electricity in the national economy, it is essential to study the effect of environmental regulations on the electricity sector. This paper aims at making an economic analysis of Korea's power plant utilities by comparing electricity generation costs from coal-fired power plants and liquefied natural gas (LNG) combined cycle power plants with environmental consideration. In this study, the levelized generation cost method (LGCM) is used for comparing economic analysis of power plant utilities. Among the many pollutants discharged during electricity generation, this study principally deals with control costs related only to CO₂ and NO₂, since the control costs of SO₂ and total suspended particulates (TSP) are already included in the construction cost of utilities. The cost of generating electricity in a coal-fired power plant is compared with such cost in a LNG combined cycle power plant. Moreover, a sensitivity analysis with computer simulation is performed according to fuel price, interest rates and carbon tax. In each case, these results can help in deciding which utility is economically justified in the circumstances of environmental regulations.     

Trade-off in emissions of acid gas pollutants and of carbon dioxide in fossil fuel power plants with carbon capture

This paper investigates the impact of capture of carbon dioxide (CO₂) from fossil fuel power plants on the emissions of nitrogen oxides (NO_X) and sulphur oxides (SO_X), which are acid gas pollutants. This was done by estimating the emissions of these chemical compounds from natural gas combined cycle and pulverized coal plants, equipped with post-combustion carbon capture technology for the removal of CO₂ from their flue gases, and comparing them with the emissions of similar plants without CO₂ capture. The capture of CO₂ is not likely to increase the emissions of acid gas pollutants from individual power plants; on the contrary, some NO_X and SO_X will also be removed during the capture of CO₂. The large-scale implementation of carbon capture is however likely to increase the emission levels of NO_X from the power sector due to the reduced efficiency of power plants equipped with capture technologies. Furthermore, SO_X emissions from coal plants should be decreased to avoid significant losses of the chemicals that are used to capture CO₂. The increase in the quantity of NO_X emissions will be however low, estimated at 5% for the natural gas power plant park and 24% for the coal plants, while the emissions of SO_X from coal fired plants will be reduced by as much as 99% when at least 80% of the CO₂ generated will be captured.     

Part-load analysis of a chemical looping combustion (CLC) combined cycle with CO2 capture

This paper presents part-load evaluation of a natural gas-fired chemical looping combustion (CLC) combined cycle with CO₂ capture. The novel combined cycle employs an air-based gas turbine, a CO₂-turbine and a steam turbine cycle. In this combined cycle, the CLC reactors replace combustion chamber of the gas turbine. The proposed combined cycle has a net plant efficiency of about 52.2% at full-load, including CO₂ compression to 200 bar. The part-load evaluation shows that reducing the load down to 60% results in an efficiency drop of 2.6%-points. However, the plant shows better relative part-load efficiency compared to conventional combined cycles. The pressure in CLC-reduction and -oxidation reactors is balanced by airflow control, using a compressor equipped with variable guide vanes. A combination of control strategies is discussed for plant start-up and shutdown and for part-load when airflow reduction is not practically possible with current generation of compressors. The results show that the combined cycle has a promising efficiency even at part-load; however, it requires an advanced control strategy.     

Perspectives for the direct firing of biomass as a supplementary fuel in combined cycle power plants

An analysis of the performance of a gas turbine–steam turbine combined cycle with supplementary firing has been carried out. Natural gas is fired in the main combustor of the cycle, whereas biomass fuel is considered as the supplementary fuel. Although, supplementary firing is found to reduce the overall cycle efficiency, the low cost of biomass and the CO₂‐neutral attribute of its combustion reduce the specific fuel cost and specific CO₂ emission. The effects of pressure and temperature ratios of the topping cycle and main steam conditions of the bottoming cycle on the performance parameters of the combined cycle have been studied at different degrees of supplementary firing. The topping cycle temperature ratio is found to be the most critical parameter and its low value gives substantial advantages in lowering the fuel cost and CO₂ emission. Marginal advantages are also achieved at higher pressure ratio and better bottoming cycle main steam conditions. Copyright © 2008 John Wiley & Sons, Ltd.     

Hydrogen production from fossil fuels with carbon capture and storage based on chemical looping systems

This paper analyzes innovative processes for producing hydrogen from fossil fuels conversion (natural gas, coal, lignite) based on chemical looping techniques, allowing intrinsic CO₂ capture. This paper evaluates in details the iron-based chemical looping system used for hydrogen production in conjunction with natural gas and syngas produced from coal and lignite gasification. The paper assesses the potential applications of natural gas and syngas chemical looping combustion systems to generate hydrogen. Investigated plant concepts with natural gas and syngas-based chemical looping method produce 500 MW hydrogen (based on lower heating value) covering ancillary power consumption with an almost total decarbonisation rate of the fossil fuels used.The paper presents in details the plant concepts and the methodology used to evaluate the performances using critical design factors like: gasifier feeding system (various fuel transport gases), heat and power integration analysis, potential ways to increase the overall energy efficiency (e.g. steam integration of chemical looping unit into the combined cycle), hydrogen and carbon dioxide quality specifications considering the use of hydrogen in transport (fuel cells) and carbon dioxide storage in geological formation or used for EOR.     

Thermodynamic analysis of solar energy use for reforming fuels to hydrogen

In this paper, a method is proposed for reforming fuels to hydrogen using solar energy at distributed locations (industrial sites, residential and commercial buildings fed with natural gas, remote settlements supplied by propane etc). In order to harness solar energy a solar concentrator is used to generate high temperature heat to reform fuels to hydrogen. A typical fuel such as natural gas, propane, methanol, or an atypical fuel such as ammonia or urea can be transported to distributed locations via gas networks or other means. The thermodynamic analysis of the process shows the general reformation reactions for NH₃, CH₄ and C₃H₈ as the input fuel by comparison through operational fuel cost and CO₂ mitigation indices. Through a cost analysis, cost reduction indices show fuel-usage cost reductions of 10.5%, 22.1%, and 22.2% respectively for the reformation of ammonia, methane, and propane. CO₂ mitigation indices show fuel-usage CO₂ mitigations of 22.1% and 22.3% for methane and propane respectively, where ammonia reformation eliminates CO₂ emission at the fuel-usage stage. The option of reforming ammonia is examined in further detail as proposed cycles for solar energy capture are considered. A mismatch of specific heats from the solar dish is observed between incoming and outgoing streams, allowing a power production system to be included for a more complete energy capture. Further investigation revealed the most advantageous system with a direct expansion turbine being considered rather than an external power cycle such as Brayton or Rankine type cycles. Also, an energy efficiency of approximately 93% is achievable within the reformation cycle.     

CO2 capture from the industry sector

It is widely accepted that greenhouse gas emissions, especially CO₂, must be significantly reduced to prevent catastrophic global warming. Carbon capture and reliable storage (CCS) is one path towards controlling emissions, and serves as a key component to climate change mitigation and will serve as a bridge between the fossil fuel energy of today and the renewable energy of the future. Although fossil-fueled power plants emit the vast majority of stationary CO₂, there are many industries that emit purer streams of CO₂, which result in reduced cost for separation. Moreover, many industries outside of electricity generation do not have ready alternatives for becoming low-carbon and CCS may be their only option. The thermodynamic minimum work for separation was calculated for a variety of CO₂ emissions streams from various industries, followed by a Sherwood analysis of capture cost. The Sherwood plot correlates the relationship between concentrations of a target substance with the cost to separate it from the remaining components. As the target concentration increases, the cost to separate decreases on a molar basis. Furthermore, the lowest cost opportunities for deploying first-of-a-kind CCS technology were found to be in the Midwest and along the Gulf Coast. Many high purity industries, such as ethanol production, ammonia production and natural gas processing, are located in these regions. The southern Midwest and Gulf Coast are also co-located with potential geologic sequestration sites and enhanced oil recovery opportunities. As a starting point, these sites may provide the demonstration and knowledge necessary for reducing carbon capture technology costs across all industries, and improving the economic viability for CCS and climate change mitigation. The various industries considered in this review were examined from a dilution and impact perspective to determine the best path forward in terms of prioritizing for carbon capture. A possible implementation pathway is presented that initially focuses on CO₂ capture from ethanol production, followed by the cement industry, ammonia, and then natural gas processing and ethylene oxide production. While natural gas processing and ethylene oxide production produce high purity streams, they only account for relatively small portions of industrial process CO₂. Finally, petroleum refineries account for almost a fifth of industrial process CO₂, but are comprised of numerous low-purity CO₂ streams. These qualities make these three industries less attractive for initial CC implementation, and better suited for consideration towards the end of the industrial CC pathway.     

CO2 control technology effects on IGCC plant performance and cost

As part of the USDOE's Carbon Sequestration Program, an integrated modeling framework has been developed to evaluate the performance and cost of alternative carbon capture and storage (CCS) technologies for fossil-fueled power plants in the context of multi-pollutant control requirements. This paper uses the newly developed model of an integrated gasification combined cycle (IGCC) plant to analyze the effects of adding CCS to an IGCC system employing a GE quench gasifier with water gas shift reactors and a Selexol system for CO₂ capture. Parameters of interest include the effects on plant performance and cost of varying the CO₂ removal efficiency, the quality and cost of coal, and selected other factors affecting overall plant performance and cost. The stochastic simulation capability of the model is also used to illustrate the effect of uncertainties or variability in key process and cost parameters. The potential for advanced oxygen production and gas turbine technologies to reduce the cost and environmental impacts of IGCC with CCS is also analyzed.     

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.     

Integration of gas switching combustion in a humid air turbine cycle for flexible power production from solid fuels with near-zero emissions of CO2 and other pollutants

This work presents a novel plant configuration for power production from solid fuels with integrated CO₂ capture. Specifically, the Gas Switching Combustion (GSC) system is integrated with a Humid Air Turbine (HAT) power cycle and a slurry fed entrained flow (GE-Texaco) gasifier or a dry fed (Shell) gasifier with a partial water quench. The primary novelty of the proposed GSC-HAT plant is that the reduction and oxidation reactor stages of the GSC operation can be decoupled allowing for flexible operation, with the oxygen carrier serving as a chemical and thermal energy storage medium. This can allow the air separation unit, gasifier, gas clean-up, CO₂ compressors and downstream CO₂ transport and storage network to be downsized for operation under steady state conditions, while the reactors and the power cycle operate flexibly to follow load. Such cost-effective flexibility will be highly valued in future energy systems with high shares of variable renewable energy. The GSC-HAT plant achieves 42.5% electrical efficiency with 95.0% CO₂ capture rate with the Shell gasifier, and 41.6% efficiency and 99.2% CO₂ capture with the GE gasifier. An exergy analysis performed for the GE gasifier case revealed that this plant reached 38.9% exergy efficiency, only 1.6%-points below an inflexible GSC-IGCC benchmark configuration, while reaching around 5%-points higher CO₂ capture rate. Near-zero SO_x and NO_x emissions are achieved through pre-combustion gas clean-up and flameless fuel combustion. Overall, this flexible and efficient near-zero emission power plant appears to be a promising alternative in a future carbon constrained world with increasing shares of variable renewables and more stringent pollutant (NO_x, SO_x) regulations.     

High-efficiency power production from natural gas with carbon capture

A unique electricity generation process uses natural gas and solid oxide fuel cells at high electrical efficiency (74%HHV) and zero atmospheric emissions. The process contains a steam reformer heat-integrated with the fuel cells to provide the heat necessary for reforming. The fuel cells are powered with H₂ and avoid carbon deposition issues. 100% CO₂ capture is achieved downstream of the fuel cells with very little energy penalty using a multi-stage flash cascade process, where high-purity water is produced as a side product. Alternative reforming techniques such as CO₂ reforming, autothermal reforming, and partial oxidation are considered. The capital and energy costs of the proposed process are considered to determine the levelized cost of electricity, which is low when compared to other similar carbon capture-enabled processes.     

Techno-economic and environmental performances of glycerol reforming for hydrogen and power production with low carbon dioxide emissions

This paper is evaluating from the conceptual design, thermal integration, techno-economic and environmental performances points of view the hydrogen and power generation using glycerol (as a biodiesel by-product) reforming processes at industrial scale with and without carbon capture. The evaluated hydrogen plant concepts produced 100,000 Nm³/h hydrogen (equivalent to 300 MW_th) with negligible net power output for export. The power plant concepts generated about 500 MW net power output. Hydrogen and power co-generation was also assessed. The CO₂ capture concepts used alkanolamine-based gas–liquid absorption. The CO₂ capture rate of the carbon capture unit is at least 90%, the carbon capture rate of the overall reforming process being at least 70%. Similar designs without carbon capture have been developed to quantify the energy and cost penalties for carbon capture. The various glycerol reforming cases were modelled and simulated to produce the mass & energy balances for quantification of key plant performance indicators (e.g. fuel consumption, energy efficiency, ancillary energy consumption, specific CO₂ emissions, capital and operational costs, production costs, cash flow analysis etc.). The evaluations show that glycerol reforming is promising concept for high energy efficiency processes with low CO₂ emissions.     

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 European power plant infrastructure—Presentation of the Chalmers energy infrastructure database with applications

This paper presents a newly established database of the European power plant infrastructure (power plants, fuel infrastructure, fuel resources and CO₂ storage options) for the EU25 member states (MS) and applies the database in a general discussion of the European power plant and natural gas infrastructure as well as in a simple simulation analysis of British and German power generation up to the year 2050 with respect to phase-out of existing generation capacity, fuel mix and fuel dependency. The results are discussed with respect to age structure of the current production plants, CO₂ emissions, natural gas dependency and CO₂ capture and storage (CCS) under stringent CO₂ emission constraints.