Liquid air energy storage (LAES) is a large-scale storage technology, which is using liquefied air as storage medium. Comparable to pumped hydro (PHES) and compressed air energy storage (CAES), LAES is charged with excess electricity from the grid and discharged, when the electricity demand is high. Working as a buffer for the electric grid, the availability and integrability of fluctuating renewable energy sources can be improved by LAES. In the charging process, ambient air is liquefied with an adopted Claude respectively Kapitza process. Compression heat is stored in a hot thermal energy storage device (HTES); a cold thermal energy storage device (CTES) is used as heat sink at cryogenic temperature to significantly improve the efficiency of the liquefaction. In the discharging process, liquid air is pressurized, heated up to ambient temperature by the CTES, superheated by the HTES, and expanded in an air expander for electricity generation. The CTES is used to recycle an exergy flow at cryogenic temperature from the discharging to the charging process. Since the round trip efficiency of the LAES strongly depends on this exergy flow, two different types of CTES are compared within this work. The liquid cold thermal energy storage device (LCTES) is based on a multi-tank storage system using propane and methanol, the direct cold thermal energy storage device (DCTES) is a packed bed storage system with direct contact between the fluid and the solid storage material. In this work, a comparison and an exergetic investigation of both systems is presented. The significant influence of the exergetic efficiency of the CTES and other technical aspects are worked out. Additionally, the influence of the pressure on the liquefaction and discharging process, and on the round trip efficiency is investigated. (C) 2019 The Authors. Published by Elsevier Ltd.

The current paper presents measurements of the normal spectral and total emittances of mixtures of different powdery material, all typical constituents of coal ashes. Measurement of sample surface temperature, a key parameter for the calculation of emittance, is carried out by thermocouples and by two-colour pyrometry. Two size fractions of 0 to 32 µm and 125 to 160 µm were examined. The influence of particle size on emittance is investigated by measurement of mixtures of different size fractions of SiO2. In addition, mixtures of CaCO3, CaSO4, K2SO4, Fe2O3 are examined. Measurements were made from 500 up to 1000 °C. The spectra were recorded from 1.6 µm to 12 µm, the major wavelength range for radiative heat transfer in boilers. The results show that the larger the particle size, the higher the emittance. In carbonate/sulfate mixtures absorption bands are visible in the spectra. Fe2O3 shows no absorption bands and seems to dominate the spectra when mixed with carbonates or sulfates.

Metal combustion is currently under discussion as a possible basis for a closed energy loop. One potential metal with several benefits for such a process is lithium. While the reaction products in conventional combustion processes are gaseous, the reaction products of lithium combustion are solid (Li2CO3, Li2O) and, hence, easy to capture and to recycle. The current paper describes the lay-out and optimization of a 100 MWth lithium slag tap furnace by computational fluid dynamics (CFD) using CO2 as oxidizer for the lithium. ANSYS Fluent has been extended by two lithium combustion models developed by the authors. The first reference model is one-step model directly converting Li to Li2CO3, neglecting the intermediate species Li2O. The second extended model is a two-step model considering Li2O as intermediate species. Simulations were carried out using a fixed geometry of the slag tab, varying the injection angle of gas and lithium spray and the CO2-Li ratio with respect to the lithium conversion level and lithium product capture efficiency. The simulations show that a high capture efficiency of lithium combustion products is possible when a large injection angle is used. The conversion level is highly dependent on injection angle, CO2-Li ratio and the Li combustion model used. While the conversion level of the reference model is inherently limited and lies between 84 and 87.6%, the extended model predicts significantly higher conversion levels in the order of 96.7-99.2% which would be needed for industrial application.

Lithium combustion has been discussed as a possible basis for a closed energy loop. While the reaction products in conventional combustion processes are gaseous, the reaction products of lithium combustion are solid (Li2CO3, Li2O) and hence easy to capture and to recycle. The current paper describes the lay-out and optimization of a 100 MWth lithium slag tap furnace by computational fluid dynamics (CFD) using CO2 as oxidizer for the lithium. ANSYS Fluent has been extended by a lithium combustion model developed by the authors. Simulations with five different gas and particle injection angles and three atmospheres with different CO2-fuel ratios were conducted to investigate the lithium conversion level and separation efficiency. The simulations show, that a high separation efficiency of lithium combustion products is possible when a large injection angle is used. The conversion level on the other hand is highly dependent on both injection angle and CO2-fuel ratio and lies between 84 and 87.6%.

The application of CCS technology involves considerable efficiency losses and significant additional investments. The aim is therefore to reduce these efficiency losses and to cut costs. Against this background, membrane-based carbon capture routes for the post-combustion, oxyfuel and pre-combustion technology lines will be analyzed in the following for hard-coal-fired power plants. To the best knowledge of the authors, this paper is the first one comparing membrane based capture routes on common technical and economic boundary conditions. The post-combustion process involves a cascade arrangement of polymer membranes. In the optimum case, the efficiency losses for this concept amount to 9.6 percentage points. In comparison, efficiency losses for the other two membrane-based concepts, i.e. oxyfuel (oxygen transport membrane (OTM) with vacuum pump) and pre-combustion (water-gas shift reactor-WGSMR), are considerably lower (5.3/5.5 percentage points). The main goal of this paper is to assess levelized cost of electricity (LCOE) for the process routes under consideration and their sensitivity on CO2 allowance costs, yearly operating hours, membrane costs and membrane lifetime. The specific investment costs for the capture plants are 2410(sic)/kWh (oxyfuel), 2572(sic)/kW h (post-combustion) and 2660(sic)/kWh (pre-combustion). This is 66% (post-combustion), 55% (oxyfuel) and 33% (pre-combustion) above the specific investment costs for the corresponding reference case without carbon capture. Allowance prices in a range from (sic)20 (pre-combustion) to (sic)39 (post-combustion) per tonne of CO2 would be necessary to compensate for the additional investments. Since it can be assumed that the membranes have a limited lifetime, the influence on electricity generation costs was calculated for different lifetimes. The results show that a technical service life of more than 3 years does not have a significant impact on generation costs. This applies to all the technological concepts investigated. In terms of LCOE and CO2 avoidance costs ((sic)/t(co2)) it turns out that oxyfuel and pre-combustion based membrane power plants are favorable compared to the post-combustion route. However, it has to be kept in mind that the uncertainty in membrane costs are higher for the oxyfuel membranes (ceramic oxygen transport membranes) and the pre-combustion membranes (microporous ceramic membranes) compared to the polymeric post-combustion membranes which already have achieved a commercial level. (C) 2015 Published by Elsevier Ltd.

Combustion and temperature measurement of single lithium particles (d(p) < 250 mu m) with CO2 was carried out in a laminar flow reactor. An imaging two-color pyrometer system was used to measure particle and flame size as well as combustion temperatures. The results indicate two different combustion phenomena, which have been identified in literature before: Gas-phase reaction at temperatures above 2500 K and surface reaction of lithium with CO2 at temperatures between 1500 and 1800 K. In addition, a sampling probe was utilized to extract burning particles from the reactor. The extracted probes were analyzed concerning their constituents using X-ray diffraction analysis and their shape and surface with scanning electron microscopy. The results showed lithium carbonate as main reaction product and a relatively smooth surface of the particles after burn-out. Combining the experimental findings, a single particle combustion model was suggested and apparent reaction kinetics was determined. (C) 2015 Elsevier Ltd. All rights reserved.

A numerical model for the ignition and combustion of lithium particles (d(p) = 20-250 mu m) in pure CO2 atm(o)sphere was developed and implemented in ANSYS Fluent's "discrete phase model". The combustion model is based on experimental findings gained in a laminar flow reactor: the experiments indicate two reaction mechanisms: An initial high temperature above gas-phase combustion (>2500 K) with a reaction zone apart from the particle surface ("stand-of flame") followed by a surface reaction at lower temperature (1500-1800 K). As reaction kinetics is only available for the surface reaction, a theoretical approach was established to calculate duration and mass conversion of the gas-phase reaction. The complete model includes inert heating, lithium melting and the reaction steps described above and enables the complete calculation of single particle or droplet combustion of lithium.The results of the numerical simulation were compared to experiments conducted in a laminar flow reactor. As the numerical results show, the predicted combustion behavior is in good agreement with the experimental results. (C) 2015 Published by Elsevier Ltd.

Pre-combustion-carbon-capture is one of the three main routes for the mitigation of CO2-emissions by fossil fueled power plants. Based on the data of a detailed technical evaluation of CO2-capture by porous ceramic membranes (CM) and ceramic membrane reactors (WGSMR) in an Integrated-Gasification-Combined-Cycle (IGCC) power plant this paper focuses on the economic effects of CO2-abatement. First the results of the process simulations are presented briefly. The analysis is based on a comparison with a reference IGCC without CO2-capture (dry syngas cooling, bituminous coal, efficiency of 47.4%). In addition, as a second reference, an IGCC process with CO2 removal based on standard Selexol-scrubbing is taken into account. The most promising technology for CO2-capture by membranes in IGCC applications is the combination of a water gas shift reactor and a H-2-selective membrane into one water gas shift membrane reactor. For the WGSRM-case efficiency losses can be limited to about 6%-points (including losses for CO2 compression) for a CO2 separation degree of 90%. This is a severe reduction of the efficiency loss compared to Selexol (10.3% points) or IGCC-CM (8.6% points). The economic evaluation is based on a detailed analysis of investment and operational costs. Parameters like membrane costs and lifetime, costs of CO2-certificates and annual operating hours are taken into account. The purpose of these evaluations is to identify the minimum cost of electricity for the different capture cases for the variation of the boundary conditions. Fixing 90% CO2 separation the analysis identifies clearly that the economic minimum for cost of electricity and maximum thermodynamic efficiencies do not coincide. The cost of electricity for the reference case was 67 (sic)/MW h and for the WGSMR integration with 90% CO2 separation 57 (sic)/MW h, if certificate costs of 30 (sic)/t(CO2), membrane costs of 300 (sic)E/m(2) and 8000 operating hours/year are considered. Further studies on the sensitivity of cost of electricity on the technical and commercial boundary conditions will be presented. (C) 2014 Elsevier Ltd. All rights reserved.

In this paper pre-combustion CO2-capture via porous ceramic membranes in lignite fired IGCC power plants is investigated. Four different cases were configured with Aspen Plus and Epsilon, including a reference case without carbon capture and three cases with carbon capture. The capture technologies were a porous ceramic membrane and a ceramic membrane reactor with simultaneous CO2 separation and CO-shift. Two different water gas-shift configurations were combined with the membrane reactor. Sensitivity analyses of membrane area and permeation pressure were done for the capture cases to investigate the influence on membrane and power plant performance and identify the optimum conditions from an energetic viewpoint. All capture concepts showed capture rates over97.5% and the achievable efficiency losses lay between 6.8 and 9.4%-points.