Underground coal gasification (UCG) is a promising clean coal technology. Typically, the syngas obtained from UCG is used for power generation via the steam turbine route. In the present paper, we consider UCG as a hydrogen generator and investigate the possibility of coupling it with a solid oxide fuel cell (SOFC) to generate electrical power directly. We show, through analysis, that integration with SOFC gives two specific advantages. Firstly, because of the high operating temperature of the SOFC, its anode exhaust can be used to produce steam required for the operation of UCG as well as for the reforming of the syngas for the SOFC. Secondly, the SOFC serves as a selective absorber of oxygen from air which paves the way for an efficient system of a carbon-neutral electrical power generation from underground coal. Thermodynamic analysis of the integrated system shows considerable improvement in the net thermal efficiency over that of a conventional combined cycle plant. © 2011, Hydrogen Energy Publications, LLC. Published by Elsevier Ltd. All rights reserved.

Sreenivas Jayanti

Department Of Chemical Engineering

Carbon sequestration

Cycle analysis

Hydrogen generations

SOLID OXIDE

Underground coal gasification

Carbonization

Coal

Coal gasification

Combined cycle power plants

Electric generators

Hydrogen

Hydrogen production

Solid oxide fuel cells (SOFC)

Steam reforming

Steam turbines

Synthesis gas

Thermoanalysis

Gas generators

IIT Madras is a public technical and research university located in Chennai, Tamil Nadu. Founded in 1959, it is recognised as an Institute of National Importance.

IIT Madras has been ranked as the top engineering institute in India for four years in a row by the National Institutional Ranking Framework of the MHRD

It currently offers undergraduate, postgraduate and research degrees across 16 disciplines in Engineering, Sciences, Humanities and Management. About 596 faculty belonging to science and engineering departments and centres of the Institute are engaged in teaching, research and industrial consultancy.

IIT Madras

International Journal of Hydrogen Energy

Gasification of solid fuels such as coals, lignite and biomasses has been studied using isothermal and non-isothermal thermogravimetric analysis (TG) with CO2 as gasifying agent. Non-isothermal TG of three Indian coals (two bituminous and one sub-bituminous coal), one lignite and two biomass fuels (Casuarina and empty fruit bunches) at a constant heating rate of 20 °C min-1 in the temperature range from 25 to 1200 °C showed a clear separation of DTG peaks associated with pyrolysis and CO2 gasification. Based on these studies, isothermal TG experiments were conducted in the temperature range from 900 to 1100 °C for coals and from 800 to 1000 °C for biomass fuels. These results show that the CO2 gasification rate follows coal rank for the three coals and the lignite. The two biomasses have significantly higher reactivities than the three coals. The higher reactivity of one coal is attributed to the presence of calcium-containing minerals in its inorganic matter. The kinetic parameters for each fuel were extracted from the isothermal TG results using the volumetric reaction model for the coals and a zeroth-order model for biomass fuels. Biomass and lignite are found to have a much higher reactivity index and much lower conversion time than the three coals under identical conditions. © 2015 Akadémiai Kiadó, Budapest, Hungary.

Journal of Thermal Analysis and Calorimetry

Evaluation of CO2 gasification kinetics for low-rank Indian coals and biomass fuels

Emission of carbon dioxide from fossil fuel-fired thermal power plants is a major concern for energy providers all around the world. In this context, carbon capture from thermal power plants and the energy penalty incurred in the process are important issues. The present work reports on a detailed analysis of gas-fired power plant layouts with in-built carbon capture, i.e. the flue gas from these power plants contains mainly carbon dioxide and water vapour. Four layouts, two of which are based on pressurized oxyfuel combustion and two on chemical looping combustion (CLC), have been considered. Based on detailed mass balance, energy and thermodynamic analyses of the power plant layouts, the net efficiencies for each plant have been computed. After accounting for thermodynamic irreversibilities and CO2 compression to 110 bar, these have been found to vary between 31 and 52 % for the four plants. Despite the technological maturity of oxyfuel combustion, it is concluded that CLC-based plants would be future-ready in the sense that they can readily accommodate CCS with only 2 % loss in overall thermal efficiency for CO2 capture. © 2015 Springer-Verlag.

Clean Technologies and Environmental Policy

Comparative analysis of four gas-fired, carbon capture-enabled power plant layouts

CLC (chemical looping combustion) promises to be a more efficient way of CO2 capture than conventional oxy-fuel combustion or post-combustion absorption. While much work has been done on CLC in the past two decades, the issue of multi-fuel compatibility has not been addressed sufficiently, especially with regard to plant layout and reactor design. In the present work, it is shown that this is non-trivial in the case of a CLC-based power plant. The underlying factors have been examined in depth and design criteria for fuel compatibility have been formulated. Based on these, a layout has been developed for a power plant which can run with either natural gas or syngas without requiring equipment changes either on the steam side or on the furnace side. The layout accounts for the higher CO2 compression costs associated with the use of syngas in place of natural gas. The ideal thermodynamic cycle efficiency, after accounting for the energy penalty of CO2 compression, is 43.11% and 41.08%, when a supercritical steam cycle is used with natural gas and syngas, respectively. It is shown that fuel switching can be enabled by incorporating the compatibility conditions at the design stage itself. © 2014 Elsevier Ltd.

Energy

Viability of fuel switching of a gas-fired power plant operating in chemical looping combustion mode

Underground coal gasification (UCG) is a transient and evolving phenomenon in which many chemical and physical changes occur simultaneously and/or sequentially in various regions throughout the coal seam. Heat affected zones of dry and volatile depleted porous zones are formed up to a certain depth of the coal block leading to coal spalling. In the present work, we present a proximate analysis of the coal samples from various locations of the heat-affected zone (HAZ) during borehole combustion and gasification studies which simulate experimentally underground coal gasification. Results from HAZ studies of wood and four coals show that there is a considerable change in the volatiles to fixed carbon ratio in the depth direction and that the extent of variation depends on the coal as well as on the conditions prevailing during the experiment. These results have a potential bearing on the reactivity of the coal and the product gas composition. © 2014 Elsevier Ltd.

Fuel

Heat-affected zone analysis of high ash coals during ex situ experimental simulation of underground coal gasification

Underground coal gasification (UCG) is a potential clean coal technology which converts coal into combustible gas in situ. The syngas produced from the UCG process using dry air contains more steam, tar and higher hydrocarbons compared to the conventional gasifiers. The focus of the present work is to use solid oxide fuel cells (SOFCs) to produce electrical power efficiently. To this end, a UCG system, based on air alone as the gasifying medium, is integrated with the SOFC system taking advantage of the high temperature exhaust from the latter to reform the syngas for producing hydrogen. Additional power is produced in the conventional way from a steam turbine making use of the unutilized fuel in SOFC. A detailed energy analysis of this system shows more than 4% thermal efficiency gain over an electricity generating system based entirely on a steam turbine cycle. © 2012 Elsevier Ltd.

Applied Energy

Underground coal-air gasification based solid oxide fuel cell system

Oxy-fuel combustion is one of the technologies which enable the economic and efficient carbondioxide (CO 2) removal. In the present paper, a new variant to the oxy-coal combustion in a pulverized coal burner is proposed in which CO 2-enriched flue gas is used to moderate the flame temperature in conventional oxy-fuel combustion. In this method, a flue gas conditioner is used to remove most of the moisture from the flue gas which results in CO 2 enrichment. This gas is recycled back to the furnace to be mixed with pure oxygen from an air separation unit to provide a CO 2-rich environment in which the hydrocarbon fuel is burnt. Thermodynamic analysis on a lignite coal-fired power plant shows that, for the same peak flame temperature, the flue gas is significantly richer in CO 2 (by up to 80.5% by mass) at the boiler exit. Compared to the conventional exhaust gas recycling, the proposed method is simpler in the sense that one hot-gas particulate cleaning system is eliminated. The volumetric flow rate of the flue gas through the boiler is also reduced. Both these factors make it attractive for high ash coals where particulate cleaning and erosion-related problems are of major concern. Thermodynamic exergy analysis shows that the optimized CO 2-enriched flue gas recycled power plant performs better than retrofitted flue gas recycled system. © 2008 Elsevier Ltd. All rights reserved.

Optimized enriched CO 2 recycle oxy-fuel combustion for high ash coals

Studies on the growth of three-dimensional cavity geometries in underground coal gasification (UCG) are important in exploiting the large fraction of coal that is present in underground coal seams. In the present study, the cavity formation in UCG has been simulated using experiments carried out in three configurations: (i) sublimation experiments in camphor simulating primarily the heat transfer aspects, (ii) bore hole combustion in Acacia nilotica wood bringing in chemical reaction into play, and (iii) bore hole combustion a coal block bringing into consideration the effect of ash on the cavity formation. In all the three cases, the time-evolution of the cavity shape has been monitored under constant oxygen flow rate conditions by measuring the cavity shape and size at periodic intervals. Results show that the cavity formation rates as well as the shape of the cavity are significantly affected by the oxidant flow rate. The importance of the ash present in the coal on the cavity growth has also been brought out. A fair amount of gasification leading to the formation of H2, CO and CH4 was observed; this is shown to depend both on the inherent moisture as well as on the reaction zone temperature. © 2011 Elsevier Ltd.

Simulation of cavity formation in underground coal gasification using bore hole combustion experiments

The objective of the present paper is to propose a new variant of the oxy-fuel combustion for carbondioxide (CO2) sequestration in which steam is used to moderate the flame temperature. In this process, pure oxygen is mixed with steam and the resulting oxidant mixture is sent to the boiler for combustion with a fossil fuel. The advantage of this method is that flue gas recirculation is avoided and the volumetric flow rates through the boiler and auxiliary components is reduced by about 39% when compared to the conventional air-fired coal combustion power plant leading to a reduction in the size of the boiler. The flue gas, after condensation of steam, consists primarily of CO 2 and can be sent directly for compression and sequestration. Flame structure analysis has been carried out using a 325-step reaction mechanism of methane-oxidant combustion to determine the concentration of oxygen required to ensure a stable flame. Thermodynamic exergy analysis has also been carried out on SMOC-operated CO2 sequestration power plant and air-fired power plant, which shows that though the gross efficiency increases the absolute power penalty of ∼8% for CO2 sequestration when compared to air-fired power plant. © 2010 Elsevier Ltd. All rights reserved.

Journal	International Journal of Hydrogen Energy
ISSN	03603199
Open Access	No