A Sorbent Enhanced Reforming technology to produce clean hydrogen from natural gas is being developed by GTI Energy in collaboration with Cranfield University. A small pilot (0.071 MWth) had been previously constructed and operated at the Energy and Environmental Research Center (EERC) in North Dakota, USA. In 2016, the small pilot was relocated to GTI Energy Headquarters in Des Plaines, Illinois, USA, for improvements and further operation, shown in Figure 1. The 0.071 MWth pilot was reconfigured to test an indirectly fired calciner which enables direct capture of the carbon dioxide as a separate product stream. The work, under a U.S. Department of Energy (DOE) funded contract, validated the sorbent entrainment in a fluidized bed reactor. A subsequent DOE contract, DE-EE0008637, initiated developmental testing of the needed components and culminated in the commissioning and testing of the reconfigured pilot in 2023. The pilot has achieved continuous operation and hydrogen production within ±2% of the chemical equilibrium.

The combustion of coal and biomass fuels in power plants generates deposits on the surfaces of superheater / reheater tubes that can lead onto fireside corrosion. This type of materials degradation can limit the lives of such tubes in the long term, and better methods are needed to produce predictive models for such damage. This paper reports on four different approaches that are being investigated to tackle the challenge of modelling fireside corrosion damage on superheaters / reheaters: (a) CFD models to predict deposition onto tube surfaces; (b) generation of a database of available fireside corrosion data; (c) development of mechanistic and statistically based models of fireside corrosion from laboratory exposures and dimensional metrology; (d) statistical analysis of plant derived fireside corrosion datasets using multi-variable statistical techniques, such as Partial Least Squares Regression (PLSR). An improved understanding of the factors that influence fireside corrosion is resulting from the use of a combination of these different approaches to develop a suite of models for fireside corrosion damage.

The integration of solar energy into coal-fired power plants has been proven as a potential approach in the utilization of solar energy to reduce coal consumption. Moreover, solar augmentation offers low cost and low risk alternatives to stand-alone solar thermal power plants. In this study, the annual performance of a solar tower aided coal-fired power (STACP) system is investigated, and the influence of thermal storage system capacity on the annual solar generating power and annual solar-to-electricity efficiency is explored. The thermal storage system capacity is optimized to obtain the lowest levelized cost of electricity (LCOE). At the same time, the influence and sensitivity of several important economic factors are explored and assessed. Results demonstrate that compared to a coal-fired power system, the reduction in the annual average coal consumption rate of the STACP system with high direct normal irradiance (DNI), medium DNI, and low DNI are 5.79, 4.52, and 3.22 g/kWh, respectively. At a minimum, the annual coal consumption can be reduced by 14,000 tin a 600 MW, power generation unit. Because the same solar field is considered under different DNI conditions, the LCOE in the high DNI, medium DNI, and low DNI scenarios are all fairly similar (6.37, 6.40, and 6.41 (sic)/kWh, respectively). When the solar multiple is 3.0, the optimal thermal storage capacity of the STAG' system, with high, medium, and low DNIs are 6.73, 4.42, and 2.21 h, respectively. The sensitivity analysis shows that the change in economic parameters exerts more influence on the STAG' system with the high DNI compared with the other two scenarios.

Fossil fuels have traditionally been used in power generation systems and represent the main source of greenhouse gas emissions from this sector. Renewable fuels, especially biomass, are now being substituted for fossil fuels to reduce CO2 emissions. Co-firing biomass with coal, which has been widely practised in the UK and Europe, is one route to reduce the environmental impact of using coal. However, the deposition of ash particles and vapour species on heat exchanger surfaces during operation is a serious issue in pulverised coal and biomass fired power plant as this reduces the plant thermal efficiency and can cause fireside corrosion, which limits component lives. Deposit formation is difficult to predict as it varies with many factors including: boiler geometry, combustion conditions and fuel composition. Computational Fluid Dynamics (i.e. CFD) is one of the best modelling tools to study the flow behaviour of gases and particles around heat exchanger tubes and predict deposition. This work used an Eulerian-Lagrangian model to describe the gas flow field around tubes and the solid ash particle trajectories respectively. User Defined Functions (i.e. UDFs) were developed for the CFD package to enable the prediction of deposit growth, deposit shape and temperature gradients around superheater/reheater tubes. Deposit build up insulates such tubes from the flow of the hot combusted gas stream and reduces heat transfer between this gas stream and the steam coolant following within the tubes, thus raising the deposit temperature. The CFD-based predictions generated were consistent with available literature data. The CFD deposition model has been applied to predict deposition on air cooled ceramic probes in a 100 kWth pilot-scale, pulverized fuel (PF) combustor and compared to deposition data measured after the combustor rig runs. For modelling purposes, the geometry was simplified to a two-dimensional domain with inert spherical ash particles dispersed in air and injected at an inlet plane. Experimental data from a series of rig runs have been used to test this CFD deposition modelling approach.

A Solar Tower Aided Coal-fired Power (STACP) system utilizes a solar tower coupled to a conventional coal-fired power system to reduce pollutants, greenhouse gas emissions and the investment of solar energy facilities. This paper examines three different schemes for integrating solar energy into a conventional boiler. For each scheme, an energy and exergy analysis of a 600 MWe supercritical coal-fired power system is combined with 53 MWth of solar energy in both a fuel saving mode and a power boosting mode. The results show that, for all these integration schemes, the boiler's efficiency and system's efficiency are reduced. However, the standard coal consumption rate is lower in comparison to conventional power plants and the standard coal consumption rate in the fuel saving mode is lower than that in the power boosting mode for all three schemes. Comprehensively considering both the standard coal consumption rate and efficiency, the scheme that uses solar energy to heat superheat steam and subcooled feed-water is the best integration option. Compared with a coal-fired only system, the saved standard coal consumption rate of the above mentioned scheme in fuel saving mode and power boosting mode can reach up to 11.15 g/kWh and 11.11 g/kWh, respectively. Exergy analysis shows, for STACP system, exergy losses of boiler and solar field contribute over 88% of whole system's exergy loss.

Solar aided coal-fired power system has been proven to be a promising way to utilise solar energy in large scale. In this paper, the performances of the solar tower aided coal-fired power (STACP) system at 100% load, 75% load, and 50% load for different days are investigated and the maximum solar power that the boiler can absorb under different plant loads are explored. Then, the effects of solar multiple (SM) and the thermal energy storage (TES) hour on the daily performance of STACP system are investigated. Results show that the maximum solar power that a 600 MWe boiler can absorb at 100% load, 75% load and 50% load are 76.4 MWth, 54.2 MWth and 23.0 MWth, respectively. Due to the augmented energy from the solar field, the maximum standard coal consumption rate is reduced by 13.53 g/kWh, 12.81 g/kWh and 8.22 g/kWh at 100% load, 75% load and 50% load, respectively. With an increase of solar power input, the boiler efficiency, overall system efficiency and solar thermal-to-electricity efficiency show a downward trend. In addition, the daily coal consumption of summer solstice is the lowest while the winter solstice is the highest for a particular SM and TES hour. (C) 2018 Elsevier Ltd. All rights reserved.

Integrated gasification combined cycles can incorporate pre-combustion carbon capture. High-H2 syngas produces high H2O levels after combustion, potentially accelerating gas turbine component damage. Determining materials systems’ suitability for this novel environment requires exposures in representative environments. Thus, an existing 0.7 MW burner rig was modified to generate the combustion environment and incorporate a cascade of 15 air-cooled turbine blades. Computational fluid dynamic calculations using blade dimensions and flow requirements supported the cascade design and determined blade placement within the gas flow. Trials of the modified unit have shown that a simulated combusted H2-rich syngas composition was generated at gas temperatures ≤1440°C. A 1000 h exposure has been carried out with thermal barrier coated blades to demonstrate the operation of the unit. This paper is part of a thematic issue on the 9th International Charles Parsons Turbine and Generator Conference. All papers have been revised and extended before publication in Materials Science and Technology. GRAPHICAL ABSTRACT

Carbon capture and storage (CCS) from natural gas-fired systems is an emerging field and many of the concepts and underlying scientific principles are still being developed. Preliminary studies suggest this approach can boost the CO2 content in the feed gas up to 3 times compared to the 'no recycle' case (CO2 concentration increased to 18% vs. 6%), with a consequent reduction in flow to the post-combustion capture unit by a factor of three compared to conventional, non-S-EGR. For this project, Cranfield University developed a pilot-scale 100 kW CO2 membrane rig facility in order to investigate simultaneously EGR and S-EGR technologies, the latter being achieved by using a CO2 sweep air polymeric membrane. A bench-scale membrane rig has also been developed to investigate the permeability and selectivity of different polymeric membranes to CO2. Currently a small-scale polydimethylsiloxane (PDMS) membrane module is also being investigated to study its selectivity/permeability. The tests include exploring the performance improvement of the PDMS membrane using different operating conditions with a view to developing scale-up procedures for the membrane unit for the actual 100 kW pilot-scale rig. Process simulations were performed using Aspen Plus software to predict the behaviour of the pilot-scale rig using a model developed based on empirical parameters (i.e., mass transfer coefficient of CO2 through the membrane and permeance), measured in the bench-scale membrane test unit. The results show that CO2 concentrations of up to 14.9% (comparable to CO2 level in coal combustion) can be achieved with 60% EGR, with a 90% CO2 removal efficiency of the membrane units. However, the results generated with the membrane model in which specific permeance values to PDMS were applied, predicted concentrations of CO2 in flue gases up to 9.8% (v/v) for a selective recycle of 60%. The study shows that the S-EGR technique is an effective method that can provide similar conditions to that of a coal-fired power plant for the post-combustion capture system operating on natural gas-fired units, but also highlights the fact that more research is required to find more suitable materials for membranes that optimise the CO2 removal efficiencies from the flue gas.

This paper presents the experimental results from co-firing blends of El Cerrejon (EC) coal and cereal coproduct (CCP) using several ratios (100/0; 75/25; 50/50; 0/100 (w/w)) under air-and oxy-firing conditions, in a retrofitted 100 kWth pulverised fuel combustor. An on-line high-resolution multi-component Fourier Transform Infra-red (FTIR) analyser was used to measure CO2, O-2, H2O, CO, NO, NO2, N2O, NH3, SO2, HCl, HF and CH4. A comprehensive evaluation of the major and minor species present in the flue gas was carried out to study the effects of the addition of biomass, the firing mode (air/oxy) and the type of recycle (wet/dry) on the gaseous environment in the combustor. It was found that similar CO2 levels can be reached when using pure coal or pure biomass, on a dry basis. For the minor species, the increase in the share of biomass had the effect of decreasing the SO2 levels reached in the flue gas and increasing the HCl content. No significant variation in the NOx levels was observed as a consequence of using high percentages of biomass. For ash deposit characterisation, two probes were used for which surface temperatures were controlled at 650 degrees and 750 degrees C. Environmental scanning electron microscopy (ESEM) with energy dispersive X-ray (EDX) analysis, supported by X-ray diffraction (XRD), were used to study the deposits. The ESEM/EDX and XRD results showed similar sulphur levels in the deposits when varying the share of biomass even though EC coal contains 3.5 times more sulphur than CCP. This is thought to be a consequence of the reaction of sulphur with the alkalis, especially potassium, present at higher levels in the CCP, which produces higher levels of K2SO4 in the combustion gas. Chlorine was only found in the deposits generated using pure CCP under oxy-firing conditions. An evaluation of the different mineral species formed when varying the biomass share and the firing mode was also performed. Results obtained comparing the mineral species in deposits when using 100% CCP, switching from air to oxyfiring conditions, showed that in air-firing CCP deposits had higher levels of aluminium phosphate and arcanite (K2SO4). Also, under oxy-firing conditions, 100% CCP-derived deposits had a higher level of potassium magnesium chloride compared 100% EC. (C) 2017 Published by Elsevier Ltd.

Components of gas turbines (such as blades, vanes, combustor cans) exposed to combustion environments at high temperature are susceptible to hot corrosion attack. To successfully plan maintenance and to determine whether to operate in novel combustion modes (e.g., in integrated gasification combined cycles that incorporate pre‐combustion carbon capture) predictions of hot corrosion component life must be made. In this paper, hot corrosion datasets relating to two alloys, MarM 509 (a cobalt‐based superalloy), and Rene 80 (a nickel‐based superalloy) form the basis of hot corrosion predictive lifetime models. The model framework is based on the two stages of incubation and propagation, with the transitions from incubation to propagation around the samples being based on Weibull statistics. The impact of a range of temperatures (including 700 and 900 °C), gas compositions (simulating the combustion of natural gas, H2‐rich syngas, or partially cleaned syngas), and deposit chemistries/fluxes have been assessed. Predictions have been made including the expected damage spread for a range of different exposure conditions.

Pollutant emissions from coal-fired power system have been receiving increasing attention over the past few years. Integration of solar thermal energy can greatly reduce pollutant emissions from these power stations. The performances of coal-fired power system (S1), solar aided coal-fired power system with thermal storage (S2), and solar aided coal-fired power system without thermal storage (S3) with three capacities of each kind of system (i.e., nine subsystems) were analyzed over the entire life span. The pollutant emissions and primary energy consumptions (PECs) of S1, S2, and S3 were estimated using life cycle assessment (LCA). The evaluation value of global warming potential (GWP), acidification potential (AP), respiratory effects potential (REP) and PEC were obtained based on the LCA results. Furthermore, the system investments were estimated, and grey relation theory was used to evaluate the performance of the three types of systems comprehensively. Finally, in order to find the effect of some main factors on the solar aided coal-fired power system (SACFPS), uncertainty analysis has been carried out. The LCA results show that the pollutant emissions and PEC mainly take place in the fuel processing and operation stages for all three system types, and S2 performs the best among the three systems based on the grey relation analysis results. And the uncertainty analysis shows that with longer life span, the power system have better performance; with higher coal price, the power system will have worse performance; with lower solar collector field cost, the solar aided coal-fired power system will be more profitable than the base-case coal-fired power system. (C) 2016 Elsevier Ltd. All rights reserved.

The use of naturally occurring ores as oxygen carriers in CLC processes is attractive because of their relative abundance and low cost. Unfortunately, they typically exhibit lower reactivity and lack the mechanical robustness required, when compared to synthetically produced carriers. Impregnation is a suitable method for enhancing both the reactivity and durability of natural ores when used as oxygen carriers for CLC systems. This investigation uses impregnation to improve the chemical and mechanical properties of a Brazilian manganese ore and a Canadian iron ore. The manganese ore was impregnated with Fe2O3 and the iron ore was impregnated with Mn2O3 with the goal of forming a combined Fe/Mn oxygen carrier. The impregnated ore's physical characteristics were assessed by SEM, BET and XRD analysis. Measurements of the attrition resistance and crushing strength were used to investigate the mechanical robustness of the oxygen carriers. The impregnated ore's mechanical and physical properties were clearly enhanced by the impregnation method, with boosts in crushing strength of 11-26% and attrition resistance of 37-31% for the impregnated iron and manganese ores, respectively. Both the unmodified and impregnated ore's reactivity, for the conversion of gaseous fuel (CH4 and syngas) and gaseous oxygen release (CLOU potential) were investigated using a bench-scale quartz fluidised-bed reactor. The impregnated iron ore exhibited a greater degree of syngas conversion compared to the other samples examined. Iron ore based oxygen carrier's syngas conversion increases with the number of oxidation and reduction cycles performed. The impregnated iron ore exhibited gaseous oxygen release over extended periods in an inert atmosphere and remained at a constant 0.2% 02 concentration by volume at the end of this inert period. This oxygen release would help ensure the efficient use of solid fuels. The impregnated iron ore's reactivity for CH4 conversion was similar to the reactivity of its unmodified counterpart. The unmodified manganese ore converted CH4 to the greatest extent of all the samples tested here, while the impregnated manganese ore exhibited a decrease in reactivity with respect to syngas and CH4 conversion. Crown Copyright (C) 2015 Published by Elsevier Ltd. This is an open access article under the CC BY license.

To reduce the emissions of greenhouse gases, the power generation industry is increasingly moving towards higher operating steam temperatures (and pressures) and more efficient ultra super critical (USC) boilers. However, higher operating temperatures coupled with biomass derived fuel can lead to aggressive corrosion damage to the superheater reheater tubes. This paper presents a systematic evaluation of high velocity oxy fuel (HVOF) thermal sprayed FeCrAl coating onto a 9% Cr boiler steel. The coated samples were exposed in a series of laboratory-based fireside corrosion tests in simulated coal-biomass co-fired combustion gases for 1000 h at 700, 750 and 800 °C. The tests were carried out using the deposit-recoat test method to simulate the environment that anticipated from air-firing 20 wt.% cereal co-product (CCP) mixed with a UK coal. The exposures were carried out using a screening deposit containing Na2SO4, K2SO4 and Fe2O3 to produce alkali-iron tri-sulphates, which had been identified as being the principal cause of fireside corrosion on superheaters and reheaters in pulverized fuel power plants. Pre- and post-exposure dimensional metrology was used to quantify the metal damage in terms of metal loss distributions. The exposed samples were examined in an environmental scanning electron microscope (ESEM) to characterize the oxide scales and damage. At 700 °C, FeCrAl coating provided suitable protection (median metal damage of ~ 85 μm) to the steel substrate; however, at 750 °C, the median metal loss of the coating was ~ 260 μm and ~ 305 μm at 800 °C. Sulphur was detected at the coating-scale interface and an aluminium-rich mixed oxide formed at the outer scale and a chromium-rich mixed oxide formed in the inner layer. The concentration of aluminium in the coating depleted to ~ 6 at.% following the 1000 h exposure.

A study was carried out to investigate the CO2 capture performance of limestone under atmospheric carbonations following pressurised calcination. A series of tests was carried out to study the role of pressurised calcination using a fluidised bed reactor. In this investigation, calcination of limestone particles was carried out at three levels of pressure: 0.1MPa, 0.5MPa, and 1.0MPa. After calcination, the capture performance of the calcined sorbent was tested at atmospheric pressure. As expected, the results indicate that the carbonation conversion of calcined sorbent decreases as the pressure is increased during calcination. Pressurised calcination requires higher temperatures and causes an increase in sorbent sintering, albeit that it would have the advantage of reducing equipment size as well as the compression energy necessary for CO2transport and storage, and an analysis has been provided to give an assessment of the potential benefits associated with such an option using process software.

Oxy-fuel combustion is a promising and relatively new technology to facilitate CO2 capture and sequestration (CCS) for power plants utilising hydrocarbon fuels. In this research experimental oxy-combustion trials and simulation are carried out by firing pulverised coal and biomass and co-firing a mixture of them in a 100 kW retrofitted oxy-combustor at Cranfield University. The parent fuels are coal (Daw Mill) and biomass cereal co-product (CCP) and experimental work was done for 100 % coal (w/w), 100 % biomass (w/w) and a blend of coal 50 % (w/w) and biomass 50 % (w/w). The recirculation flue gas (RFG) rate was set at 52 % of the total flue gas. The maximum percentage of CO2 observed was 56.7 % wet basis (73.6 % on a dry basis) when 100 % Daw Mill coal was fired. Major and minor emission species and gas temperature profiles were obtained and analysed for different fuel mixtures. A drop in the maximum temperature of more than 200 K was observed when changing the fuel from 100 % Daw Mill coal to 100 % cereal co-product biomass. Deposits formed on the ash deposition probes were also collected and analysed using the environmental scanning electron microscopy (ESEM) with energy-dispersive X-ray (EDX) technique. The high sulphur, potassium and chlorine contents detected in the ash generated using 100 % cereal co-product biomass are expected to increase the corrosion potential of these deposits. In addition, a rate-based simulation model has been developed using Aspen Plus® and experimentally validated. It is concluded that the model provides an adequate prediction for the gas composition of the flue gas.

Fuel Flexible Energy Generation: Solid, Liquid and Gaseous Fuels provides updated information on flexible fuel energy generation, the process by which one or more fuels can be combusted in the same boiler or turbine to generate power. By adapting or building boilers and turbines to accept multiple fuel sources, they can be co-fired with biomass and waste derived fuels, allowing a reduction in carbon output, thus providing cleaner energy. Fuel flexibility is becoming more important in a world of diminishing fossil fuel stocks. Many countries are investing in the development of more efficient fuel flexible boilers and turbines, and their use is becoming more prevalent in industry as well. This book provides comprehensive coverage of flexible fuel energy generation across all potential fuel types, and was written by a selection of experts in the field who discuss the types of fuels which can be used in fuel flexible energy generation, from solid fuels to biomass fuels, the preparation of fuels to be used in fuel flexible operations, that includes their handling and transport, and combustion and conversion technologies with chapters ranging from large-scale coal gasification to technology options and plant design issues. Focuses on fuel flexibility across all potential fuel types Includes thorough treatment of the technology being developed to allow for fuel flexibility Written by leading experts in the field Provides an essential text for R&D managers in firms which produce boilers or turbines, those who work in the fuel industry, and academics working in engineering departments on energy generation

To reduce CO2 emissions, there is interest in a new generation of industrial gas turbines operating in advanced integrated gasification combined cycles (IGCC) with the option for pre-combustion CO2 removal systems. These gas turbines may be fired on syngas, cleaned H-2 rich syngas, or natural gas, and this will alter the hot corrosion experienced by components in the hot gas path. Deposit recoat laboratory tests have looked at the response of 11 state-of-the-art materials systems under the expected IGCC conditions. MTData has been used to calculate the optimal deposits under the temperature and gas conditions for these tests. Studies of metal loss have helped assess quantitatively the resistance of the different materials systems, while microscopy techniques have given information on the degradation mechanisms experienced. Rene 80 has been selected to demonstrate the data from these tests and shows the most significant metal loss under partially cleaned syngas conditions.

Engineering scale-up challenges, and potential effects of SO2 on the calcium looping cycle for post combustion CO2 capture have been investigated in Cranfield University's pilot scale reactor (25 kWth). Following reactor and process modifications, close to 80% capture was achieved. SO2 was found to have a detrimental effect on the calcium looping cycle in both batch and continuous cyclic tests, although the presence of steam from natural gas-fired burners was found to have a positive effect on maintaining capture capacity of the sorbent.