CO2 capture efficiency and energy requirement analysis of power plant using modified calcium-based sorbent looping cycle

This paper examines the average carbonation conversion, CO₂ capture efficiency and energy requirement for post-combustion CO₂ capture system during the modified calcium-based sorbent looping cycle. The limestone modified with acetic acid solution, i.e. calcium acetate is taken as an example of the modified calcium-based sorbents. The modified limestone exhibits much higher average carbonation conversion than the natural sorbent under the same condition. The CO₂ capture efficiency increases with the sorbent flow ratios. Compared with the natural limestone, much less makeup mass flow of the recycled and the fresh sorbent is needed for the system when using the modified limestone at the same CO₂ capture efficiency. Achieving 0.95 of CO₂ capture efficiency without sulfation, 272 kJ/mol CO₂ is required in the calciner for the natural limestone, whereas only 223 kJ/mol CO₂ for the modified sorbent. The modified limestone possesses greater advantages in CO₂ capture efficiency and energy consumption than the natural sorbent. When the sulfation and carbonation of the sorbents take place simultaneously, more energy is required. It is significantly necessary to remove SO₂ from the flue gas before it enters the carbonator in order to reduce energy consumption in the calciner.     

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.     

CO2 capture performance of calcium-based sorbent doped with manganese salts during calcium looping cycle

The effects of manganese salts including Mn(NO₃)₂ and MnCO₃ on CO₂ capture performance of calcium-based sorbent during cyclic calcination/carbonation reactions were investigated. Mn(NO₃)₂ and MnCO₃ were added by wet impregnation method. The cyclic CO₂ capture capacities of Mn(NO₃)₂-doped CaCO₃, MnCO₃-doped CaCO₃ and original CaCO₃ were studied in a twin fixed-bed reactor and a thermo-gravimetric analyzer (TGA), respectively. The results show that the addition of manganese salts improves the cyclic carbonation conversions of CaCO₃ except the previous cycles. When the Mn/Ca molar ratios are 1/100 for Mn(NO₃)₂-doped CaCO₃ and 1.5/100 for MnCO₃-doped CaCO₃, the highest carbonation conversions are achieved respectively. The carbonation temperature of 700-720 °C is beneficial to CO₂ capture of Mn-doped CaCO₃. The residual carbonation conversions of Mn(NO₃)₂-doped and MnCO₃-doped CaCO₃ are 0.27 and 0.24 respectively after 100 cycles, compared with the conversion of 0.16 for original one after the same number of cycles. Compared with calcined original CaCO₃, better pore structure is kept for calcined Mn-doped CaCO₃ during calcium looping cycle. The pore volume of calcined MnCO₃-doped CaCO₃ is 2.4 times as high as that of calcined original CaCO₃ after 20 cycles. The pores of calcined MnCO₃-doped CaCO₃ in the pore size range of 27-142 nm are more abundant relative to clacined original one. That is why modification by manganese salts can improve cyclic CO₂ capture capacity of CaCO₃.     

Sorbent enhanced hydrogen production from steam gasification of coal integrated with CO2 capture

In this work, CO₂ capture and H₂ production during the steam gasification of coal integrated with CO₂ capture sorbent were investigated using a horizontal fixed bed reactor at atmospheric pressure. Four different temperatures (650, 675, 700, and 750 °C) and three sorbent-to-carbon ratios ([Ca]/[C] = 0, 1, 2) were studied. In the absence of sorbent, the maximum molar fraction of H₂ (64.6%) and conversion of coal (71.3%) were exhibited at the highest temperature (750 °C). The experimental results verified that the presence of sorbent in the steam gasification of coal enhanced the molar fraction of H₂ to more than 80%, with almost all CO₂ was fixed into the sorbent structure, and carbon monoxide (CO) was converted to H₂ and CO₂ through the water gas shift reaction. The steam gasification of coal integrated with CO₂ capture largely depended on the reaction temperature and exhibited optimal conditions at 675 °C. The maximum molar fraction of H₂ (81.7%) and minimum CO₂ concentration (almost 0%) were obtained at 675 °C and a sorbent-to-carbon ratio of 2.     

Liquid CO2 droplet extraction from gases

Efficient mechanical separation of CO₂ from combustion effluent affects the utilization potential of high CO₂ producers such as coal. Novel mechanical separations of condensing CO₂ from gas flows need to be able to capture the small condensed droplets below the cyclone cut-off limit of 20 μm. We describe the thermodynamics, the energy costs and droplet formation of CO₂ phase separation from combustion effluent and natural gas. We report the first measurements of condensing CO₂ droplet sizes from gas. This shows that application of homogeneous condensation of CO₂ yields much smaller droplets in flue gas (N₂/CO₂) than from contaminated natural gas (CH₄/CO₂). These small droplets can only be efficiently removed at high throughputs using the novel centrifugal method we describe. Such mechanical separations are preferable to the current standard chemical methods because of the much lower environmental footprint.     

Recent developments in membrane-based technologies for CO2 capture

Developing new methods and technologies that compete with conventional industrial processes for CO₂ capture and recovery is a hot topic in the current research. Conventional processes do not fit with the current approach of process intensification but take advantage due to their maturity and large-scale implementation. Acting in a precombusion scenario or post-combustion scenario involves the separation of CO₂/H₂ or CO₂/N₂, respectively.     

Coal gasification with in situ CO2 capture by the synthetic CaO sorbent in a 1 kWth dual fluidised-bed reactor

Coal gasification with in situ CO₂ capture is believed to be able to produce highly concentrated H₂ with little or no CO₂ compared with the conventional process. This has been demonstrated by other researchers working on a single fluidised bed by continuously feeding the CaO sorbent. This work presents the results of coal gasification with in situ CO₂ capture by a synthetic CaO sorbent in a 1 kW_th dual fluidised-bed reactor at atmospheric pressure, which has not been reported in the literature. The synthetic CaO sorbent is cyclically used by going through multiple carbonation/calcination cycles during coal gasification.     

High capacity potassium-promoted hydrotalcite for CO2 capture in H2 production

This paper presents an experimental study for a newly modified K₂CO₃-promoted hydrotalcite material as a novel high capacity sorbent for in-situ CO₂ capture. The sorbent is employed in the sorption enhanced steam reforming process for an efficient H₂ production at low temperature (400–500 ^°C). A new set of adsorption data is reported for CO₂ adsorption over K-hydrotalcite at 400 °C. The equilibrium sorption data obtained from a column apparatus can be adequately described by a Freundlich isotherm. The sorbent shows fast adsorption rates and attains a relatively high sorption capacity of 0.95 mol/kg on the fresh sorbent. CO₂ desorption experiments are conducted to examine the effect of humidity content in the gas purge and the regeneration time on CO₂ desorption rates. A large portion of CO₂ is easily recovered in the first few minutes of a desorption cycle due to a fast desorption step, which is associated with a physi/chemisorption step on the monolayer surface of the fresh sorbent. The complete recovery of CO₂ was then achieved in a slower desorption step associated with a reversible chemisorption in a multi-layer surface of the sorbent. The sorbent shows a loss of 8% of its fresh capacity due to an irreversible chemisorption, however, it preserves a stable working capacity of about 0.89 mol/kg, suggesting a reversible chemisorption process. The sorbent also presents a good cyclic thermal stability in the temperature range of 400–500 °C.     

Technologies for increasing CO2 concentration in exhaust gas from natural gas-fired power production with post-combustion, amine-based CO2 capture

Enhanced CO₂ concentration in exhaust gas is regarded as a potentially effective method to reduce the high electrical efficiency penalty caused by CO₂ chemical absorption in post-combustion capture systems. The present work evaluates the effect of increasing CO₂ concentration in the exhaust gas of gas turbine based power plant by four different methods: exhaust gas recirculation (EGR), humidification (EvGT), supplementary firing (SFC) and external firing (EFC). Efforts have been focused on the impacts on cycle efficiency, combustion, gas turbine components, and cost. The results show that the combined cycle with EGR has the capability to change the molar fraction of CO₂ with the largest range, from 3.8 mol% to at least 10 mol%, and with the highest electrical efficiency. The EvGT cycle has relatively low additional cost impact as it does not require any bottoming cycle. The externally fired method was found to have the minimum impacts on both combustion and turbomachinery.     

Two novel oxy-fuel power cycles integrated with natural gas reforming and CO2 capture

Two novel system configurations were proposed for oxy-fuel natural gas turbine systems with integrated steam reforming and CO₂ capture and separation. The steam reforming heat is obtained from the available turbine exhaust heat, and the produced syngas is used as fuel with oxygen as the oxidizer. Internal combustion is used, which allows a very high heat input temperature. Moreover, the turbine working fluid can expand down to a vacuum, producing an overall high-pressure ratio. Particular attention was focused on the integration of the turbine exhaust heat recovery with both reforming and steam generation processes, in ways that reduce the heat transfer-related exergy destruction. The systems were thermodynamically simulated, predicting a net energy efficiency of 50–52% (with consideration of the energy needed for oxygen separation), which is higher than the Graz cycle energy efficiency by more than 2 percentage points. The improvement is attributed primarily to a decrease of the exergy change in the combustion and steam generation processes that these novel systems offer. The systems can attain a nearly 100% CO₂ capture.     

Pre-combustion, post-combustion and oxy-combustion in thermal power plant for CO2 capture

This paper presents a summary of technical-economic studies. It allows evaluating, in the French context, the production cost of electricity derived from coal and gas power plants with the capture of CO₂, and the cost per tonne of CO₂ avoided. Three systems were studied: an Integrated Gasification Combined Cycle (IGCC), a conventional combustion of Pulverized Coal (PC) and a Natural Gas Combined Cycle (NGCC). Three main methods were envisaged for the capture of CO₂: pre-combustion, post-combustion and oxy-combustion.For the IGCC, two gasification types have been studied: a current technology based on gasification of dry coal at 27 bars (Shell or GE/Texaco radiant type) integrated into a classical combined cycle providing 320 MWe, and a future technology (planned for about 2015–2020) based on gasification of a coal–water mixture (slurry) that can be compressed to 64 bars (GE/Texaco slurry type) integrated into an advanced combined cycle (type H with steam cooling of the combustion turbine blades) producing a gross power output of 1200 MWe.     

Effects of CO2 gas as leaks from geological storage sites on agro-ecosystems

Carbon capture and storage in geological formations has potential risks in the long-term safety because of the possibility of CO₂ leakage. Effects of leaking gas, therefore, on vegetation, soil, and soil-inhabiting organisms are critical to understand. An artificial soil gassing and response detection field facility developed at the University of Nottingham was used to inject CO₂ gas at a controlled flow rate (1 l min⁻¹) into soil to simulate build-up of soil CO₂ concentrations and surface fluxes from two land use types: pasture grassland, and fallow followed by winter bean. Mean soil CO₂ concentrations was significantly higher in gassed pasture plots than in gassed fallow plots. Germination of winter bean sown in gassed fallow plots was severely hindered and the final crop stand was reduced to half. Pasture grass showed stress symptoms and above-ground biomass was significantly reduced compared to control plot. A negative correlation (r = −0.95) between soil CO₂ and O₂ concentrations indicated that injected CO₂ displaced O₂ from soil. Gassing CO₂ reduced soil pH both in grass and fallow plots (p = 0.012). The number of earthworm castings was twice as much in gassed plots than in control plots. This study showed adverse effects of CO₂ gas on agro-ecosystem in case of leakage from storage sites to surface.     

Role of CO2 in the CH4 oxidation and H2 formation during fuel-rich combustion in O2/CO2 environments

The effect of CO₂ reactivity on CH₄ oxidation and H₂ formation in fuel-rich O₂/CO₂ combustion where the concentrations of reactants were high was studied by a CH₄ flat flame experiment, detailed chemical analysis, and a pulverized coal combustion experiment. In the CH₄ flat flame experiment, the residual CH₄ and formed H₂ in fuel-rich O₂/CO₂ combustion were significantly lower than those formed in air combustion, whereas the amount of CO formed in fuel-rich O₂/CO₂ combustion was noticeably higher than that in air. In addition to this experiment, calculations were performed using CHEMKIN-PRO. They generally agreed with the experimental results and showed that CO₂ reactivity, mainly expressed by the reaction CO₂ + H → CO + OH (R1), caused the differences between air and O₂/CO₂ combustion under fuel-rich condition. R1 was able to advance without oxygen. And, OH radicals were more active than H radicals in the hydrocarbon oxidation in the specific temperature range. It was shown that the role of CO₂ was to advance CH₄ oxidation during fuel-rich O₂/CO₂ combustion. Under fuel-rich combustion, H₂ was mainly produced when the hydrocarbon reacted with H radicals. However, the hydrocarbon also reacted with the OH radicals, leading to H₂O production. In fact, these hydrocarbon reactions were competitive. With increasing H/OH ratio, H₂ formed more easily; however, CO₂ reactivity reduced the H/OH ratio by converting H to OH. Moreover, the OH radicals reacted with H₂, whereas the H radicals did not reduce H₂. It was shown that OH radicals formed by CO₂ reactivity were not suitable for H₂ formation. As for pulverized coal combustion, the tendencies of CH₄, CO, and H₂ formation in pulverized coal combustion were almost the same as those in the CH₄ flat flame.     

A novel approach for treatment of CO2 from fossil fired power plants. Part B: The energy suitability of integrated tri-reforming power plants (ITRPPs) for methanol production

In Part A of this two-paper work, a novel approach for treatment of CO₂ from fossil fired power plants was studied. This approach consists of flue gases utilization as co-reactants in a catalytic process, the tri-reforming process, to generate a synthesis gas suitable in chemical industries for production of chemicals (methanol, DME, ammonia and urea, etc.). In particular, the further conversion of syngas to a transportation fuel, such as methanol, is an attractive solution to introduce near zero-emission technologies (i.e. fuel cells) in vehicular applications. In fact, the methanol can be used in DMFC (Direct Methanol Fuel Cell) or as fuel for on-board reforming to produce hydrogen for PEMFC (Proton Exchange Membrane Fuel Cell).     

Enhanced hydrogen-rich gas production from steam gasification of coal in a pressurized fluidized bed with CaO as a CO2 sorbent

Steam gasification of a typical Chinese bituminous coal for hydrogen production in a lab-scale pressurized bubbling fluidized bed with CaO as CO₂ sorbent was performed over a pressure range of ambient pressure to 4 bar. The compositions of the product gases were analyzed and correlated to the gasification operating variables that affecting H₂ production, such as pressure (P), mole ratio of steam to carbon ([H₂O]/[C]), mole ratio of CaO to carbon ([CaO]/[C]) and temperature (T). The experimental results indicated that the H₂ concentration was enhanced by raising the temperature, pressure and [H₂O]/[C] under the circumstances we observed. With the presence of CaO sorbent, CO₂ in the production gas was absorbed and converted to solid CaCO₃, thus shifting the steam reforming of hydrocarbons and water gas shift reaction beyond the equilibrium restrictions and enhancing the H₂ concentration. H₂ concentration was up to 78 vol% (dry basis) under a condition of 750 °C, 4 bar, [Ca]/[C] = 1 and [H₂O]/[C] = 2, while CO₂ (2.7 vol%) was almost in-situ captured by the CaO sorbent. This study demonstrated that CaO could be used as a substantially excellent CO₂ sorbent for the pressurized steam gasification of bituminous coal. For the gasification process with the presence of CaO, H₂-rich syngas was yielded at far lower temperatures and pressures in comparison to the commercialized coal gasification technologies. SEM/EDX and gas sorption analyses of solid residues sampled after the gasification showed that the pore structure of the sorbent was recovered after the steam gasification process, which was attributed to the formation of Ca(OH)₂. Additionally, a coal-CaO–H₂O system was simulated with using Aspen Plus software. Calculation results showed that higher temperatures and pressures favor the H₂ production within a certain range.     

Optimal operation of an integrated energy system including fossil fuel power generation, CO2 capture and wind

This study considers the optimization of operations for an integrated fossil-renewable energy system with CO₂ capture. The system treated consists of a coal-fired power station, a temperature-swing absorption CO₂ capture facility powered by a natural gas combustion turbine, and wind generation. System components are represented in a modular fashion using energy and mass balances. Optimization is applied to determine hourly system dispatch to maximize operating profit given energy prices and wind generation data. A CO₂ emission constraint, modeled after a California law, is enforced. Idealized and realistic scenarios are considered, along with several different system specifications. For a year of operation, simulated using available wind and energy price data, operating profit for optimized operation is shown to be approximately 20% greater than profit using a heuristic procedure. The benefit from optimization is positively correlated with electricity price variability and mean wind generation. The impact of different component specifications and different CO₂ absorption solvents on the optimal operation of the energy system is also assessed. In total, this study demonstrates that the effective operating cost of an integrated energy system operating under a CO₂ emission constraint can be substantially reduced via optimal flexible operation.     

Performance and costs of power plants with capture and storage of CO2

This paper assesses the three leading technologies for capture of CO₂ in power generation plants, i.e., post-combustion capture, pre-combustion capture and oxy-fuel combustion. Performance, cost and emissions data for coal and natural gas-fired power plants are presented, based on information from studies carried out recently for the IEA Greenhouse Gas R&D Programme by major engineering contractors and process licensors. Sensitivities to various potentially significant parameters are assessed.     

Valuation of marginal CO2 abatement options for electric power plants in Korea

The electricity generation sector in Korea is under pressure to mitigate greenhouse gases as directed by the Kyoto Protocol. The principal compliance options for power companies under the cap-and-trade include the application of direct CO₂ emission abatement and the procurement of emission allowances. The objective of this paper is to provide an analytical framework for assessing the cost-effectiveness of these options. We attempt to derive the marginal abatement cost for CO₂ using the output distance function and analyze the relative advantages of emission allowance procurement option as compared to direct abatement option. Real-option approach is adopted to incorporate emission allowance price uncertainty. Empirical result shows the marginal abatement cost with an average of €14.04/ton CO₂ for fossil-fueled power plants and confirms the existence of substantial cost heterogeneity among plants which is sufficient to achieve trading gains in allowance market. The comparison of two options enables us to identify the optimal position of the compliance for each plant. Sensitivity analyses are also presented with regard to several key parameters including the initial allowance prices and interest rate. The result of this paper may help Korean power plants to prepare for upcoming regulations targeted toward the reduction of domestic greenhouse gases.     

Enhanced ethanol steam reforming by CO2 absorption using CaO,CaO*MgO or Na2ZrO3

This paper presents results of thermodynamic analysis and experimental evaluation of hydrogen production by steam reforming of ethanol (SRE) combined with CO₂ absorption using a mixture of a solid absorbent (CaO, CaO*MgO and Na₂ZrO₃) and a Ni/Al₂O₃ catalyst. Thermodynamic analysis results indicate that a maximum of 69.5% H₂ (dry basis) is feasible at 1 atm, H₂O/C₂H₅OH = 6 (molar ratio) and T = 600 °C. whereas, the addition of a CO₂ absorbent at 1 atm, T = 600 °C and H₂O/C₂H₅OH/Absorbent = 6:1:2.5, produced a H₂ concentration of 96.6, 94.1, and 92.2% using CaO, CaO*MgO, and Na₂ZrO₃, respectively. SRE experimental evaluation achieved a maximum of 60% H₂. While combining SRE and a CO₂ absorbent exhibited a concentration of 96, 94, and 90% employing CaO, CaO*MgO, and Na₂ZrO₃, respectively at 1 atm, T = 600 °C, SV = 414 h⁻¹ and H₂O/C₂H₅OH/absorbent = 6:1:2.5 (molar ratio).     

Supercritical water oxidation of coal in power plants with low CO2 emissions

In this paper, the application of Super Critical Water Oxidation (SCWO) to direct combustion at low temperature of coal fine particles with pure oxygen for power generation is presented, including also a novel method for capturing and storing carbon dioxide as liquid. A detailed simulation model of a 100 MW_th coal-fired SWCO plant with low CO₂ emissions characterised by a steam cooled membraned SC reactor has been developed using Aspen Plus software. According to the well-known Semenov's thermal-ignition theory, the coal particle ignition temperature in SCW conditions has been also evaluated and the results have been integrated within the Aspen Plus model. This has been tested under different operating conditions. The simulation results are presented and the effects of the main plant operating conditions, such as ignition temperature, coal particle size and combustion pressure on the plant performances are discussed. The gross and net thermodynamic efficiencies of the power plant have been estimated to be around 44% and 28%, respectively. The pure oxygen production process results the main energy penalty.