Simulation of a Lignite‐Based Polygeneration System Coproducing Electricity and Tar with Carbon Capture

Lignite‐based polygeneration systems for coproducing tar and electricity with and without carbon capture and storage (CCS) were proposed and simulated. Predried lignite was pyrolyzed into coal gas, tar, and char. Coal gas was fired in a gas turbine after the cleanup process, while char was combusted in circulating fluidized‐bed (CFB) boilers. The polygeneration plant without CCS turned out to be more efficient than the conventional CFB power plant, suggesting that the former is a promising and efficient option to utilize lignite resources. Moreover, the performance and emissions of polygeneration plants with and without CCS were compared. It was shown that the more CO₂ is captured, the larger energy penalty it will cost. Therefore, a trade‐off should be made between low emissions and high efficiency.     

Modelling of an IGCC plant with carbon capture for 2020

Currently several industrial scale IGCC - carbon capture demonstration plants are being planned. Thermodynamic simulations are a useful tool to investigate the optimal plant configuration. In order to demonstrate the potential of the next generation of IGCC with CCS a thermodynamic model was developed using conventional but improved technology. The plant concept was verified and simulated for a generic hard coal and lignite. The simulation showed a net efficiency (LHV) of 38.5% and 41.9% for hard coal and lignite, respectively.The results are consistent with current studies but also indicate that major simulations were too optimistic. The auxiliary demand of an IGCC plant with carbon capture can be expected with 21 to 24% based on gross output. The drop in efficiency compared to the none-capture case is estimated with roughly 11 to 12%-points. During a sensitivity study the impact of process changes on plant efficiency and economics is evaluated. Releasing the captured CO₂ without compression is found to be economically favourable at CO₂ prices below 15 €/t and electricity prices above 100 €/MWh. Further the impact of carbon capture rate is quantified and an efficiency potential is indicated for lower CO₂ quality.     

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.     

Cost of energy analysis of integrated gasification combined cycle (IGCC) power plant with respect to CO2 capture ratio under climate change scenarios

This paper presents the results of the cost of energy (COE) analysis of an integrated gasification combined cycle (IGCC) power plant with respect to CO₂ capture ratio under the climate change scenarios. To obtain process data for a COE analysis, simulation models of IGCC power plants and an IGCC with carbon capture and sequestration (CCS) power plant, developed by the United States Department of Energy (DOE) and National Energy Technology Laboratory (NETL), have been adopted and simulated using Aspen Plus. The concept of 20-year levelized cost of energy (LCOE), and the climate change scenarios suggested by International Energy Agency (IEA) are also adopted to compare the COE of IGCC power plants with respect to CO₂ capture ratio more realistically. Since previous studies did not consider fuel price and CO₂ price changes, the reliability of previous results of LCOE is not good enough to be accepted for an economic comparison of IGCC power plants with respect to CO₂ capture ratio. In this study, LCOEs which consider price changes of fuel and CO₂ with respect to the climate change scenarios are proposed in order to increase the reliability of an economic comparison. And the results of proposed LCOEs of an IGCC without CCS power plant and IGCC with CCS (30%, 50%, 70% and 90% capture-mole basis- of CO₂ in syngas stream) power plants are presented.     

Heat integration and analysis of decarbonised IGCC sites

Integrated gasification combined cycle (IGCC) power generation systems have become of interest due to their high combined heat and power (CHP) generation efficiency and flexibility to include carbon capture and storage (CCS) in order to reduce CO₂ emissions. However, IGCC's biggest challenge is its high cost of energy production. In this study, decarbonised coal IGCC sites integrated with CCS have been investigated for heat integration and economic value analyses. It is envisaged that the high energy production cost of an IGCC site can be offset by maximising site-wide heat recovery and thereby improving the cost of electricity (COE) of CHP generation. Strategies for designing high efficiency CHP networks have been proposed based on thermodynamic heuristics and pinch theory. Additionally, a comprehensive methodology to determine the COE from a process site has been developed. In this work, we have established thermodynamic and economic comparisons between IGCC sites with and without CCS and a trade-off between the degree of decarbonisation and the COE from the heat integrated IGCC sites. The results show that the COE from the heat integrated decarbonised IGCC sites is significantly lower compared to IGCC sites without heat integration making application of CCS in IGCC sites economically competitive.     

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 assessment of pulverized coal boilers and IGCC power plants with CO2 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.     

Using short‐term resource scheduling for assessing effectiveness of CCS within electricity generation subsector

A new methodology for assessing the effectiveness of carbon capture and storage (CCS) that does explicitly consider the detailed operation of the target electricity system is proposed. The electricity system simulation consists of three phases, each one using a modified version of an economic dispatch problem that seeks to maximize the producers’ and consumers’ surplus while satisfying the technical constraints of the system. The economic dispatch is formulated as a dynamic mixed‐integer nonlinear programming problem and implemented in general algebraic modelling system (GAMS). The generating unit with CCS is designed and simulated using Aspen Plus®. In the first case study, the operation of the IEEE RTS ’96 (Institute of Electrical and Electronics Engineers One‐Area Reliability Test System—1996) is simulated with greenhouse gas (GHG) regulation implemented in the form of CO₂ permits that generators need to acquire for every unit of CO₂ that it is emitted. In the second case study, CCS is added at one of the buses and the operation of the modified IEEE RTS ’96 is again simulated with and without GHG regulation. The results suggest that the detailed operation of the target electricity system should be considered in future assessments of CCS and a general procedure for undertaking this for any GHG mitigation option is proposed. Future work will use the novel methodology for assessing the effectiveness of generating units with flexible CO₂ capture. © 2015 American Institute of Chemical Engineers AIChE J, 61: 4210–4234, 2015     

Gas turbine combustion performance test of hydrogen and carbon monoxide synthetic gas

The development of coal IGCC (Integrated Gasification Combined Cycle) technology has made it possible to exploit electricity generated from coal at a low cost. Furthermore, IGCC is a pre-requisite for the development of CCS (Carbon Capture and Storage) technology and hydrogen generated from coal. To achieve the need to reduce CO₂ emissions, Korea’s 300 MW IGCC RDD&D (Research Development, Demonstration and Dissemination) project was launched in December 2006 under the leadership of the Korea Electric Power Corporation (KEPCO), with the support of the Korea Ministry of Knowledge Economy.When a new fuel is adapted to a gas turbine (such as syngas for IGCC), it is necessary to study the gas turbine combustion characteristics of the fuel, because gas turbines are very sensitive to its physical and chemical properties. This experimental study was conducted by investigating the combustion performance of synthetic gas, which is composed chiefly of hydrogen and carbon monoxide. The results of a test on synthetic gas combustion performance were compared with the results of methane combustion, which is a major component of natural gas. The results of the combustion test of both gases were examined in terms of the turbine’s inlet temperature, combustion dynamics, emission characteristics, and flame structure.From the results of this experimental study, we were able to understand the combustion characteristics of synthetic gas and anticipate the problems when synthetic gas rather than natural gas is fuelled to a gas turbine.     

Simulation of a calcium looping CO2 capture process for pressurized fluidized bed combustion

The Canadian regulations on carbon dioxide emissions from power plants aim to lower the emissions from coal-fired units down to those of natural gas combined cycle (NGCC) units. Since coal is significantly more carbon intensive than natural gas, coal-fired plants must operate at higher net efficiencies and implement carbon capture to meet the new regulations. Calcium looping (CaL) is a promising post-combustion carbon capture (PCC) technology that, unlike other capture processes, generates additional power. By capturing carbon dioxide at elevated temperatures, the energy penalty that carbon capture technologies inherently impose on power plant efficiencies is significantly reduced. In this work, the CO₂ capture performance of a calcium-based sorbent is determined via thermogravimetric analysis under relatively high carbonation and low calcination temperatures. The results are used in an aspenONE™ simulation of a CaL process applied to a pressurized fluidized bed combustion (PFBC) system at thermodynamic equilibrium. The combustion of both natural gas and coal are considered for sorbent calcination in the CaL process. A sensitivity analysis on several process parameters, including sorbent feed rate and carbonator operating pressure, is undertaken. The energy penalty associated with the capture process ranges from 6.8–11.8 percentage points depending on fuel selection and operating conditions. The use of natural gas results in lower energy penalties and solids circulation rates, while operating the carbonator at 202 kPa(a) results in the lowest penalties and drops the solids circulations rates to below 1000 kg/s.     

The comparison study on the operating condition of gasification power plant with various feedstocks

Gasification technology, which converts fossil fuels into either combustible gas or synthesis gas (syngas) for subsequent utilization, offers the potential of both clean power and chemicals. Especially, IGCC is recognized as next power generation technology which can replace conventional coal power plants in the near future. It produces not only power but also chemical energy sources such as H₂, DME and other chemicals with simultaneous reduction of CO₂. This study is focused on the determination of operating conditions for a 300 MW scale IGCC plant with various feedstocks through ASPEN plus simulator. The input materials of gasification are chosen as 4 representative cases of pulverized dry coal (Illinois#6), coal water slurry, bunker-C and naphtha. The gasifier model reflects on the reactivity among the components of syngas in the gasification process through the comparison of syngas composition from a real gasifier. For evaluating the performance of a gasification plant from developed models, simulation results were compared with a real commercial plant through approximation of relative error between real operating data and simulation results. The results were then checked for operating characteristics of each unit process such as gasification, ash removal, acid gas (CO₂, H₂S) removal and power islands. To evaluate the performance of the developed model, evaluated parameters are chosen as cold gas efficiency and carbon conversion for the gasifier, power output and efficiency of combined cycle. According to simulation results, pulverized dry coal which has 40.93% of plant net efficiency has relatively superiority over the other cases such as 33.45% of coal water slurry, 35.43% of bunker-C and 30.81% of naphtha for generating power in the range of equivalent 300 MW.     

Reduction of Greenhouse Gas Emissions from Gas,Oil, and Coal Power Plants in Pakistan by Carbon Capture and Storage (CCS): A Review

The production of energy in Pakistan as a developing country mainly depends on consumption of fossil fuels, which are the main sources of greenhouse gas (GHG) emissions. These emissions can be mitigated by implementing carbon capture and storage (CCS) in running plants. An overview of the current and future potentials of Pakistan for CCS is provided, indicating a great potential for this technology to capture CO₂ emissions. The amine CO₂ capture process as the most mature procedure is currently applied in many oil and gas companies in Pakistan, which can be employed to capture CO₂ from other industries as well. Pakistan has a great CO₂ storage potential in oil, gas, and coal fields and in saline aquifer as well as significant resources of Mg and Ca silicates suitable as feedstock in the carbon mineralization process. For further development and implementation of CCS technologies in Pakistan, economic and policy barriers as the main obstacles should be alleviated.     

Integrated combined cycle from natural gas with CO2 capture using a Ca–Cu chemical loop

The integration in a natural gas combined cycle (NGCC) of a novel process for H₂ production using a chemical Ca–Cu loop was proposed. This process is based on the sorption‐enhanced reforming process for H₂ production from natural gas with a CaO/CaCO₃ chemical loop, but including a second Cu/CuO loop to regenerate the Ca‐sorbent. An integration of this system into a NGCC was proposed and a full process simulation exercise of different cases was carried out. Optimizing the operating conditions in the Ca–Cu looping process, 8.1% points of efficiency penalty with respect to a state‐of‐the‐art NGCC are obtained with a CO₂ capture efficiency of 90%. It was demonstrated that the new process can yield power generation efficiencies as high as any other emerging and commercial concepts for power generation from NGCC with CO₂ capture, but maintaining competing advantages of process simplification and compact pressurized reactor design inherent to the Ca–Cu looping system. © 2013 American Institute of Chemical Engineers AIChE J, 59: 2780–2794, 2013     

Combined Decarbonization of Electrical Energy Generation and Production of Synthetic Fuels by Renewable Energies and Fossil Fuels

Power generation from renewable energy sources and fossil fuels are integrated into one system. A combination of technologies in the form of a carbon capture utilization (CCU)-combined power station is proposed. The technology is based on energy generation from fossil fuels by a coal power plant with CO₂ recovery from exhaust gases, and pyrolysis of natural gas to hydrogen and carbon, completed by reverse water-gas shift for the conversion of CO₂ to CO, which will react with hydrogen in a Fischer-Tropsch synthesis for synthetic diesel. The carbon from the pyrolysis can replace other fossil carbon or can be sequestered. This technology offers significant CO₂ savings compared to the current state of technology and makes an environmentally friendly use of fossil fuels for electricity and fuel sectors possible.     

Progress in carbon dioxide capture and separation research for gasification-based power generation point sources

The purpose of the present work is to investigate novel approaches, materials, and molecules for the abatement of carbon dioxide (CO₂) at the pre-combustion stage of gasification-based power generation point sources. The capture/separation step for CO₂ from large point sources is a critical one with respect to the technical feasibility and cost of the overall carbon sequestration scenario. For large point sources, such as those found in power generation, the carbon dioxide capture techniques being investigated by the Office of Research and Development of the National Energy Technology Laboratory possess the potential for improved efficiency and reduced costs as compared to more conventional technologies. The investigated techniques can have wide applications, but the present research is focused on the capture/separation of carbon dioxide from fuel gas (pre-combustion gas) from processes such as the Integrated Gasification Combined Cycle (IGCC) process. For such applications, novel concepts are being developed in wet scrubbing with physical sorption, chemical sorption with solid sorbents, and separation by membranes. In one concept, a wet scrubbing technique is being investigated that uses a physical solvent process to remove CO₂ from fuel gas of an IGCC system at elevated temperature and pressure. The need to define an “ideal” solvent has led to the study of the solubility and mass transfer properties of various solvents. Pertaining to another separation technology, fabrication techniques and mechanistic studies for membranes separating CO₂ from the fuel gas produced by coal gasification are also being performed. Membranes that consist of CO₂-philic ionic liquids encapsulated into a polymeric substrate have been investigated for permeability and selectivity. Finally, processes based on dry, regenerable sorbents are additional techniques for CO₂ capture from fuel gas. An overview of these novel techniques is presented along with a research progress status of technologies related to membranes and physical solvents.     

High-performance oxygen transport membrane reactors integrated with IGCC for carbon capture

Precombustion carbon capture is an effective strategy to reduce large-scale CO₂ emissions, which is mainly used in the area of integrated gasification combined cycle (IGCC) power plants. Oxygen transport membranes (OTMs) were suggested as the air separation unit to produce high purity oxygen for the gasifier. However, the improvement in efficiency was limited. Here, a new IGCC process is reported based on a robust OTM reactor, where the OTM reactor is used behind the coal gasifier. This IGCC-OTM process fulfills syngas oxidation, H₂ production, and carbon capture in one unit, thus a significant decrease of the energy penalty is expectable. The membrane reactor does not use noble metal components, and exhibits high hydrogen production rates, high hydrogen separation factor (10³–10⁴), and stable performance in a gas mixture mimicking real syngas compositions from a coal gasifier with H₂S concentrations up to 1,000 ppm.     

Thermodynamic Simulation of CO2 Capture for an IGCC Power Plant using the Calcium Looping Cycle

A CO₂ capture process for an integrated gasification combined cycle (IGCC) power plant using the calcium looping cycle was proposed. The CO₂ capture process using natural and modified limestone was simulated and investigated with the software package Aspen Plus. It incorporated a fresh feed of sorbent to compensate for the decay in CO₂ capture activity during long‐term cycles. The sorbent flow ratios have significant effect on the CO₂ capture efficiency and net efficiency of the CO₂ capture system. The IGCC power plant, using the modified limestone, exhibits higher CO₂ capture efficiency than that using the natural limetone at the same sorbent flow ratios. The system net efficiency using the natural and modified limestones achieves 41.7 % and 43.1 %, respectively, at the CO₂ capture efficiency of 90 % without the effect of sulfation.     

Polygeneration of hydrogen and power based on coal gasification integrated with a dual chemical looping process: Thermodynamic investigation

This paper assesses, from a thermodynamic perspective, the conversion of coal to power and hydrogen through gasification simultaneously with a dual chemical looping processes, namely chemical looping air separation (CLAS) and water–gas shift with calcium looping CO₂ absorption (WGS-CaL). CLAS offers an advantage over other mature technologies in that it can significantly reduce its capital cost. WGS-CaL is an efficient method for hydrogen production and CO₂ capture. The three major factors, oxygen to coal (O/C), steam to coal (S/C) and CaO to coal (Ca/C) were analyzed. Moreover, the comparisons of this suggested process and the traditional processes including integrated gasification combined cycle (IGCC), integrated gasification combined cycle with carbon capture and storage (IGCC-CCS) and integrated gasification combined cycle with calcium-based chemical looping (IGCC-CaL) were discussed. And, the exergy destruction analysis of this suggested process has also been calculated.     

Modeling and Simulation for Post-Combustion Carbon Dioxide Capture from Power Plant Flue Gas with Economic Analysis

In this study three configurations, viz. conventional MEA, interstage absorber, and interstage absorber with two stripper configuration have been techno-economically evaluated for the optimized result by carrying out simulations using ASPEN PLUS. An economic model defined for carbon capture using 30 wt% MEA to reduce CO₂ in flue gas to 0.5 mol% of 550 MWe coal fired power plant resulted in increase in COE of power plant by 20.6, 17.4, and 15.6 percents for the three configurations, respectively. The CO₂-avoided cost for the three configurations are 65.94, 64.05, and 63.09 ($ /tonne of CO₂ avoided), respectively.