Techno-economic evaluation of advanced IGCC lignite coal fuelled power plants with CO2 capture

The techno-economic evaluation of four novel integrated gasification combined cycle (IGCC) power plants fuelled with low rank lignite coal with CO₂ capture facility has been investigated using ECLIPSE process simulator. The performance of the proposed plants was compared with two conventional IGCC plants with and without CO₂ capture. The proposed plants include an advanced CO₂ capturing process based on the Absorption Enhanced Reforming (AER) reaction and the regeneration of sorbent materials avoiding the need for sulphur removal component, shift reactor and/or a high temperature gas cleaning process. The results show that the proposed CO₂ capture plants efficiencies were 18.5–21% higher than the conventional IGCC CO₂ capture plant. For the proposed plants, the CO₂ capture efficiencies were found to be within 95.8–97%. The CO₂ capture efficiency for the conventional IGCC plant was 87.7%. The specific investment costs for the proposed plants were between 1207 and 1479 €/kW_e and 1620 €/kW_e and 1134 €/kW_e for the conventional plants with and without CO₂ capture respectively. Overall the proposed IGCC plants are cleaner, more efficient and produce electricity at cheaper price than the conventional IGCC process.     

Techno-economic assessment of pulverized coal boilers and IGCC power plants with CO<Subscript>2</Subscript> capture

The current studies on power plant technologies suggest that Integrated Gasification Combined Cycle (IGCC) systems are an effective and economic CO₂ capture technology pathway. In addition, the system in conventional configuration has the advantage of being more “CO₂ capture ready” than other technologies. Pulverized coal boilers (PC) have, however, proven high technical performance attributes and are economically often most practical technologies. To highlight the pros and cons of both technologies in connection with an integrated CO₂ capture, a comparative analysis of ultrasupercritical PC and IGCC is carried out in this paper. The technical design, the mass and energy balance and the system optimizations are implemented by using the ECLIPSE chemical plant simulation software package. Built upon these technologies, the CO₂ capture facilities are incorporated within the system. The most appropriate CO₂ capture systems for the PC system selected for this work are the oxy-fuel system and the postcombustion scheme using Monoethanolamine solvent scrubber column (MEA). The IGCC systems are designed in two configurations: Water gas shift reactor and Selexol-based separation. Both options generate CO₂-rich and hydrogen rich-gas streams. Following the comparative analysis of the technical performance attributes of the above cycles, the economic assessment is carried out using the economic toolbox of ECLIPSE is seamlessly connected to the results of the mass and energy balance as well as the utility usages. The total cost assessment is implemented according to the step-count exponential costing method using the dominant factors and/or a combination of parameters. Subsequently, based on a set of assumptions, the net present value estimation is implemented to calculate the breakeven electricity selling prices and the CO₂ avoidance cost.     

Techno-economic study of CO2 capture and storage in coal fired oxygen fed entrained flow IGCC power plants

The attractiveness of fossil fuel as a feedstock for power generation depends on the development of energy conversion systems that are efficient, clean and economical. Coal fired power plants are generally considered to be “dirty” since they have high CO₂ emissions, with the exception of those coal fired power plants that employ CO₂ capture technology. Among the coal fired options, Integrated Gasification Combined Cycle (IGCC) systems have the best environmental performance and are potentially suitable candidates. The objective of this work is to provide an assessment and analysis of the potential for reduction of the output of greenhouse gas from the oxygen fed entrained flow gasifier systems, including the cost and cost-effectiveness of each likely conceptual scheme.     

Techno-economic evaluation of a PVAm CO2-selective membrane in an IGCC power plant with CO2 capture

Published data for an operating power plant, the ELCOGAS 315 MWe Puertollano plant, has been used as a basis for the simulation of an integrated gasification combined cycle process with CO₂ capture. This incorporated a fixed site carrier polyvinylamine membrane to separate the CO₂ from a CO-shifted syngas stream. It appears that the modified process, using a sour shift catalyst prior to sulphur removal, could achieve greater than 85% CO₂ recovery at 95 vol% purity. The efficiency penalty for such a process would be approximately 10% points, including CO₂ compression. A modified plant with CO₂ capture and compression was calculated to cost €2320/kW, producing electricity at a cost of 7.6 € cents/kWh and a CO₂ avoidance cost of about €40/tonne CO₂.     

Partial O2-fired coal power plant with post-combustion CO2 capture: A retrofitting option for CO2 capture ready plants

In the work presented in this paper, an alternative process concept that can be applied as retrofitting option in coal-fired power plants for CO₂ capture is examined. The proposed concept is based on the combination of two fundamental CO₂ capture technologies, the partial oxyfuel mode in the furnace and the post-combustion solvent scrubbing. A 330 MW_el Greek lignite-fired power plant and a typical 600 MW_el hard coal plant have been examined for the process simulations. In a retrofit application of the ECO-Scrub technology, the existing power plant modifications are dominated by techno-economic restrictions regarding the boiler and the steam turbine islands. Heat integration from processes (air separation, CO₂ compression and purification and the flue gas treatment) can result in reduced energy and efficiency penalties. In the context of this work, heat integration options are illustrated and main results from thermodynamic simulations dealing with the most important features of the power plant with CO₂ capture are presented for both reference and retrofit case, providing a comparative view on the power plant net efficiency and energy consumptions for CO₂ capture. The operational characteristics as well as the main figures and diagrams of the plant’s heat balances are included.     

Techno-economic optimization of IGCC integrated with utility system for CO2 emissions reduction—Maximum power production in IGCC

Environmental legislation, with its increasing pressure on the energy sector to control greenhouse gases, is a driving force to reduce CO₂ emissions. In this paper, pre-combustion CO₂ capture through integration of a site utility system with an integrated gasification combined cycle (IGCC) is investigated as an option to provide a compressed CO₂-rich stream from a process site for sequestration. This work presents a two-step procedure for integration and optimization of a site utility system with an IGCC plant: (i) screening and optimization of IGCC plant performance parameters; (ii) integration and optimization of the utility system of the site with the IGCC plant. In the first step, an optimization approach applies the results of screening studies based on rigorous simulation of the IGCC. Having fixed the inlet fuel flow rate, the IGCC design parameters (including oxygen consumption, diluent flow rate and turbine exit pressure) are optimized for maximum power generation. Energy flows between the IGCC and CO₂ compression train are considered. In the second step, the economic and operating performance of the utility system integrated with the IGCC plant are modeled and optimized for minimum operating cost to find the most appropriate level of integration. In a case study illustrating the approach, 94% of the fuel is gasified; additional power generation offsets the operating costs of pre-combustion CO₂ capture.     

CO2 sequestration from coal fired power plants

The paper takes into consideration a new approach for CO₂ capture and transport, based on the formation of solid CO₂ hydrates.Carbon dioxide sequestration from power plants can take advantage of the properties of gas hydrates. The formation and decomposition of hydrates from various N₂-CO₂ mixtures has been studied experimentally in a 2 l reactor, to determine the CO₂ separation in terms of hydrate composition and residual CO₂ content in the reacted gas.Carbon dioxide acts as a co-former for the production of hydrates containing nitrogen, besides CO₂. The mixed hydrates that are obtained are less stable than simple CO₂ hydrates. When CO₂ content in the flue gas is higher than 30% by volume, the hydrates formed at 5 MPa are sufficiently concentrated (about 70% CO₂) and carbon dioxide reduction in the reacted gas is acceptable.The application of a process based on hydrate formation could be especially interesting (for CO₂ capture and transport) when connected to an oxy-coal combustion process; in this case the CO₂ content in the flue gas is very high and the hydrate formation is greatly facilitated.     

Exergoeconomic and exergoenvironmental evaluation of power plants including CO2 capture

CO₂ capture from power plants, combined with CO₂ storage, is a potential means for limiting the impact of fossil fuel use on the climate. In this paper, three oxy-fuel plants with incorporated CO₂ capture are evaluated from an economic and environmental perspective. The oxy-fuel plants, a plant with chemical looping combustion with near 100% CO₂ capture and two advanced zero emission plants with 100% and 85% CO₂ capture are evaluated and compared to a similarly structured reference plant without CO₂ capture. To complete the comparison, the reference plant is also considered with CO₂ capture incorporating chemical absorption with monoethanolamine. Two exergy-based methods, the exergoeconomic and the exergoenvironmental analyses, are used to determine the cost-related and the environmental impacts of the plants, respectively, and to reveal options for improving their overall effectiveness.For the considered oxy-fuel plants, the investment cost is estimated to be almost double that of the reference plant, mainly due to the equipment used for oxygen production and CO₂ compression. Furthermore, the exergoeconomic analysis reveals an increase in the cost of electricity with respect to the reference plant by more than 20%, with the advanced zero emission plant with 85% CO₂ capture being the most economical choice. On the other hand, a life cycle assessment reveals a decrease in the environmental impact of the plants with CO₂ capture, due to the CO₂ and NO_x emission control. This leads to a reduction in the overall environmental impact of the plants by more than 20% with respect to the reference plant. The most environmentally friendly concept is the plant with chemical looping combustion.     

Economical assessment of competitive enhanced limestones for CO2 capture cycles in power plants

CO₂ capture systems based on the carbonation/calcination loop have gained rapid interest due to promising carbonator CO₂ capture efficiency, low sorbent cost and no flue gases treatment is required before entering the system. These features together result in a competitively low cost CO₂ capture system. Among the key variables that influence the performance of these systems and their integration with power plants, the carbonation conversion of the sorbent and the heat requirement at calciner are the most relevant. Both variables are mainly influenced by CaO/CO₂ ratio and make-up flow of solids. New sorbents are under development to reduce the decay of their carbonation conversion with cycles. The aim of this study is to assess the competitiveness of new limestones with enhanced sorption behaviour applied to carbonation/calcination cycle integrated with a power plant, compared to raw limestone. The existence of an upper limit for the maximum average capture capacity of CaO has been considered. Above this limit, improving sorbent capture capacity does not lead to the corresponding increase in capture efficiency and, thus, reduction of CO₂ avoided cost is not observed. Simulations calculate the maximum price for enhanced sorbents to achieve a reduction in CO₂ removal cost under different process conditions (solid circulation and make-up flow). The present study may be used as an assessment tool of new sorbents to understand what prices would be competitive compare with raw limestone in the CO₂ looping capture systems.     

A multi-objective analysis for the retrofit of a pulverized coal power plant with a CO2 capture and compression process

The long term sustainability of fossil energy systems depends on reducing their carbon footprint and freshwater consumption. Much of the United States is or will be experiencing water shortages in the near future. Since power generation accounts for about a third of all freshwater use, reducing freshwater requirements will be of increasing importance. In addition, recent reports indicate that adding a carbon capture system may double water consumption. Thus, when designing a carbon capture and compression system, it is important to consider not only the direct costs, but also the increased environmental burden associated with increased freshwater requirements. To address these interrelated sustainability issues, a modular framework for multi-objective analysis was developed and demonstrated by minimizing freshwater consumption and levelized cost of electricity for the retrofit of a hypothetical 550 MW subcritical pulverized coal power plant with an MEA-based carbon capture and compression system.     

CO2 capture using oxygen enhanced combustion strategies for natural gas power plants

This paper describes a series of experiments conducted with natural gas in air and in mixtures of oxygen and recycled flue gas, termed O₂/CO₂ recycle combustion. The objective is to enrich the flue gas with CO₂ to facilitate its capture and sequestration. Detailed measurements of gas composition, flame temperature and heat flux profiles were taken inside CANMET's 0.3 MWth down-fired vertical combustor fitted with a proprietary pilot scale burner. Flue gas composition was continuously monitored. The effects of burner operation, including swirling of secondary stream and air staging, on flame characteristics and NO_x emissions were also studied. The results of this work indicate that oxy-gas combustion techniques based on O₂/CO₂ combustion with flue gas recycle offer excellent potential for retrofit to conventional boilers for CO₂ emission abatement. Other benefits of the technology include considerable reduction and even elimination of NO_x emissions, improved plant efficiency due to lower gas volume and better operational flexibility.     

Dynamic modelling of CO2 absorption for post combustion capture in coal-fired power plants

Power generation from fossil fuel-fired power plants is the largest single source of CO₂ emissions. Post combustion capture via chemical absorption is viewed as the most mature CO₂ capture technique. This paper presents a study of the post combustion CO₂ capture with monoethanolamine (MEA) based on dynamic modelling of the process. The aims of the project were to compare two different approaches (the equilibrium-based approach versus the rate-based approach) in modelling the absorber dynamically and to understand the dynamic behaviour of the absorber during part load operation and with disturbances from the stripper. A powerful modelling and simulation tool gPROMS was chosen to implement the proposed work. The study indicates that the rate-based model gives a better prediction of the chemical absorption process than the equilibrium-based model. The dynamic simulation of the absorber indicates normal absorber column operation could be maintained during part load operation by maintaining the ratio of the flow rates of the lean solvent and flue gas to the absorber. Disturbances in the CO₂ loading of the lean solvent to the absorber significantly affect absorber performance. Further work will extend the dynamic modelling to the stripper for whole plant analysis.     

Experimental study of ash formation during pulverized coal combustion in O2/CO2 mixtures

The present paper was addressed to mineral transformations and ash formation during O₂/CO₂ combustion of pulverized coal. Four Chinese thermal coals were burned in a drop tube furnace to generate ashes under various combustion conditions. The ash samples were characterized with XRD analysis and ⁵⁷Fe Mössbauer spectroscopy. The impacts of O₂/CO₂ combustion on mineral transformation and ash formation were explored through comparisons between O₂/CO₂ combustion and O₂/N₂ combustion. It was found that, O₂/CO₂ combustion did not significantly change the mineral phases formed in the residue ashes, but did affect the relative amounts of the mineral phases. The differences observed in the ashes formed in two atmospheres were attributed to the impact of the gas atmosphere on the combustion temperatures of coal char particles, which consequently influenced the ash formation behaviors of included minerals.     

Process analysis for polygeneration of Fischer-Tropsch liquids and power with CO2 capture based on coal gasification

This paper designs four cases to investigate the performances of the polygeneration processes, which depend on the commercially ready technology to convert coal to liquid fuels (CTL) and electricity with CO₂ sequestration. With Excel-Aspen Plus based models, mass and energy conversion are calculated in detail. The simulation shows that the thermal efficiency is down with the synfuels yield decrease though the electricity generation is increased. It also suggests that the largest low heat value (LHV) loss of coal occurs in the gasification unit. From the comparison of the four cases, prominent differences of coal energy transition appear in water-gas shift (WGS) units, Fischer-Tropsch (FT) synthesis and combined cycle processes. CO₂ capture and vent are discussed and the results show that the vent amount of CO₂ increases with the increase of percentage of the syngas going to produce electricity. The results also show that the ratio of carbon captured to total carbon increases from 58% to 93% which is an important contribution to cutting down the greenhouse gas vent.     

On the integration of CO2 capture with coal-fired power plants: A methodology to assess and optimise solvent-based post-combustion capture systems

Amine and other liquid solvent CO₂ capture systems capture have historically been developed in the oil and gas industry with a different emphasis to that expected for fossil fuel power generation with post-combustion capture. These types of units are now being adapted for combustion flue gas scrubbing for which they need to be designed to operate at lower CO₂ removal rates - around 85-90% and to be integrated with CO₂ compression systems. They also need to be operated as part of a complete power plant with the overall objective of turning fuel into low-carbon electricity.The performance optimisation approach for solvents being considered for post-combustion capture in power generation therefore needs to be updated to take into account integration with the power cycle and the compression train. The most appropriate metric for solvent assessment is the overall penalty on electricity output, rather than simply the thermal energy of regeneration of the solvent used.Methodologies to evaluate solvent performance that have been reported in the literature are first reviewed. The results of the model of a steam power cycle integrated with the compression system focusing on key parameters of the post-combustion capture plant - solvent energy of regeneration, solvent regeneration temperature and desorber pressure - are then presented. The model includes a rigorous thermodynamic integration of the heat available in the capture and compression units into the power cycle for a range of different solvents, and shows that the electricity output penalty of steam extraction has a strong dependence on solvent thermal stability and the temperature available for heat recovery. A method is provided for assessing the overall electricity output penalty (EOP), expressed as total kWh of lost output per tonne of CO₂ captured including ancillary power and compression, for likely combinations of these three key post-combustion process parameters. This correlation provides a more representative method for comparing post-combustion capture technology options than the use of single parameters such as solvent heat of regeneration.     

CO2 capture by adsorption with nitrogen enriched carbons

The success of CO₂ capture with solid sorbents is dependent on the development of a low cost sorbent with high CO₂ selectivity and adsorption capacity. Immobilised amines are expected to offer the benefits of liquid amines in the typical absorption process, with the added advantages that solids are easy to handle and that they do not give rise to corrosion problems. In this work, different alkylamines were evaluated as a potential source of basic sites for CO₂ capture, and a commercial activated carbon was used as a preliminary support in order to study the effect of the impregnation. The amine coating increased the basicity and nitrogen content of the carbon. However, it drastically reduced the microporous volume of the activated carbon, which is chiefly responsible for CO₂ physisorption, thus decreasing the capacity of raw carbon at room temperature.     

Comparative assessment of sub-critical versus advanced super-critical oxyfuel fired PF boilers with CO2 sequestration facilities

This work focuses on the techno-economic assessment of bituminous coal fired sub- and super-critical pulverised fuel boilers from an oxyfuel based CO₂ capture point of view. At the initial stage, two conventional power plants with a nominal power output of above 600 MWe based on the above steam cycles are designed, simulated and optimised. Built upon these technologies, CO₂ capture facilities are incorporated within the base plants resulting in a nominal power output of 500 MWe. In this manner, some sensible heat generated in the air separation unit and the CO₂ capture train can be redirected to the steam cycle resulting in a higher plant efficiency. The simulation results of conventional sub- and super-critical plants are compared with their CO₂ capture counterparts to disclose the effect of sequestration on the overall system performance attributes. This systematic approach allows the investigation of the effects of the CO₂ capture on both cycles. In the literature, super-critical plants are often considered for a CO₂ capture option. These, however, are not based on a systematic evaluation of these technologies and concentrate mainly on one or two key features. In this work several techno-economic plant attributes such as the fuel consumptions, the utility usages, the plant performance parameters as well as the specific CO₂ generation and capture rates are calculated and weighed against each other. Finally, an economic evaluation of the system is conducted along with sensitivity analyses in connection with some key features such as discounted cash flow rates, capital investments and plant efficiencies as well as fuel and operating costs.     

Modeling of CO2 sorption on coal

This paper discusses moderate pressure CO₂ sorption behavior of Illinois coals. The results fit the Langmuir and Dubinin–Astakhov (D–A) sorption models satisfactorily although the fit is better for D–A equation. Since factors like swelling of coal with CO₂ sorption and CO₂ dissolution in coal matrix contribute to uncertainties in estimating the void volume in and around the sample, an attempt was made to account for these by modifying the conventional adsorption equation. Re-fitting the experimental data using the modified equation results in improved fit for both models. The adsorption capacities of coals tested, as predicted by the equations, also reduce by 7% to 32%. The effect of volumetric uncertainty is more in lower rank coals than the higher rank ones. Furthermore, it explains the excess sorption behavior observed by others when extrapolated beyond the experimental pressure range.     

Predictive equations for CO2 emission factors for coal combustion, their applicability in a thermal power plant and subsequent assessment of uncertainty in CO2 estimation

The emission of carbon dioxide varies systematically with the rank and type of coal combusted. Hence use of a single default emission factor proposed by IPCC (Inter Governmental Panel on Climate Change) for entire categories coals may not be appropriate option to obtain a reliable estimate of carbon dioxide emission level or towards the preparation of national carbon dioxide inventory. Even predictive equations developed based on the coals of different origin may not work well with coals of a specific origin. Several linear predictive equations were thus developed separately for coking and non-coking coals of Indian origin for the estimation of carbon dioxide emission utilizing basic coal parameters such as VM, FC, GCV and NCV on different basis. Large numbers of authenticated data set were used for multiple regression analysis and good correlations were obtained. Those equations were also validated with different data sets of Indian coals. Its applicability towards estimation of CO₂ emission from power plant was also studied and uncertainty in CO₂ estimation is revealed. The developed equations may be utilized to get a realistic estimate of carbon dioxide emission with specific cases where Indian coals are mostly used.