Experimental and Thermo-Economic Analysis of Catalytic Gasification and Fuel Cell Power Systems

This dissertation presents a comprehensive experimental and thermo-economic evaluation of coal gasifiers with in-situ carbon capture for generating high-hydrogen and high-methane content syngas for solid oxide fuel cell power plants. The goals of this thesis were the following: to conduct lab-scale experiments on catalytic coal gasification with in situ capture of acid gases, such as CO2 and H2S; to use the experimental results to model a commercial scale catalytic, in situ capture, coal/waste gasifiers; to integrates this gasifier with a solid oxide fuel cell (SOFC) system and to an build economic model to determine the internal rate of return on investment (IRR) of this system; then to compare the IRR of these power plant designs with other fossil fuel based power plant designs with CO2 capture and sequestration (CCS); and finally, to use the techniques/models developed here create an economic model of a SOFC fueled by an anaerobic digester. In this thesis, we estimate what range of economic parameters, such as SOFC stack capital cost, electricity sale price, and capacity factor, are required so that the systems analyzed can obtain unsubsidized, positive rates of returns on investment. The following are the highlights from each of the chapters. First, a molten catalytic process has been demonstrated for converting coal into a synthesis gas consisting of roughly 20% methane and 80% hydrogen using alkali hydroxides as both catalysts and in situ CO2 & H2S capture agents. Baselines studies were also conducted using no catalyst, a weak capture agents (CaSiO3) and strong in situ capture agents for acid gases (NaOH, KOH & CaO). Parametric studies were conducted to understand the effects of temperature, pressure, catalyst composition, steam flow rate and the coal-to-catalyst ratio on the performance of the catalytic gasifier in terms of kinetics and syngas composition. Second, we conducted multi-cycle studies in which CaCO3 was calcined by heating to 900C to regenerate the CaO, which was then re-used in repeated CaO-CaCO3 cycles. We measured increased steam-coal gasification kinetics rates when using both CaO+KOH; these rates persisted even when the material was reused in six cycles of gasification and calcination. Third, we present an exergy and economic analysis of a power plant system that integrates a CaOlooping gasifier with a pressurized, solid oxide fuel cell (SOFC). We used the gas composition, steamcoal gasification rate and CO2 capture cycle degradation rate from the previous chapter as input into the model of this CaO-looping gasifier. We conducted an economic analysis of the system as a range of different operating pressures, current densities, fuel utilizations, and air stoichiometric ratios. We iv calculated an IRR of 6%/yr±4%/yr for the system when the sale price of electricity was $50/MWh if the CO2 could be used for enhanced oil recovery (EOR), where the uncertainty accounts only for an estimated uncertainty in the capital costs of +50%/-30%. We conducted a sensitivity analysis to determine the effect of changing some of the assumptions in our cost model, such as the price of the fuel cell stacks, the sale price of CO2, the sale price of electricity, the capacity factor, and the fuel price. Fourth, for comparison, we present exergy and economic analyses of two advanced coal-based power plants configurations in which the CO2 capture occurs outside of the gasifier. These cases are: an integrated gasification fuel cell cycle with a catalytic gasifier and a pressurized solid oxide fuel cell including CO2 sequestration (Adv. IGFC-CCS) and an integrated gasification combined cycle with advanced H2 and O2 membrane separation including CO2 sequestration (Adv. IGCC-CCS). Using the same economic assumptions, the IRR of the Adv. IGFC-CCS configuration was 4±3 %/yr if the CO2 can be used for EOR and 1±3 %/yr if the CO2 can only be sequestered in a saline aquifer. The IRR of the Adv. IGCC-CCS configuration with H2 and O2 membrane separation was 8±4 %/yr if the CO2 can be used for EOR and 3±3 %/yr if the CO2 must be sequestered in a saline aquifer. Fifth, we compare the IRR of these configurations with the IRR of other fossil fuel power plant configurations. For example, we present results showing which power plant configuration would yield the lowest levelized cost of electricity (LCOE) as a function of the price of CO2 emissions and a function of the price of natural gas, holding all other variables constant. Finally, we present an economic analysis of a configuration that uses biogas produced from an anaerobic digester (AD) to fuel a solid oxide fuel cell (SOFC) modeled based off of the pressurized SOFC we developed to the IGFC configurations presented earlier. We performed parametric studies of the AD-SOFC system in order to minimize the normalized capital cost ($/kW). The four independent variables were the current density, the stack pressure, the fuel utilization, and the total air stoichiometric ratio. Given our economic assumptions, our calculations show that adding a new AD-SOFC system to an existing wastewater treatment (WWT) plant could yield positives values of IRR (9%/yr ±4%/yr at $80/MWh electricity sale price), and could significantly outcompete other options for using biogas to generate electricity. AD-SOFC systems can convert WWT plants in net generators of electricity rather than net consumers of electricity while generating positives rates of return on investment, based on the assumptions of this analysis.