The implementation of efficient and cost effective thermal energy storage in concentrated solar power (CSP) applications is crucial to the wide spread adoption of the technology. The current push to high-temperature receivers enabling the use of advanced power cycles has identified solid particle receivers as a desired technology. A potential way of increasing the specific energy storage of solid particles while simultaneously reducing plant component size is to implement thermochemical energy storage (TCES) through the use of non-stoichiometric perovskite oxides. Materials such as strontium-doped lanthanum cobalt ferrites (LSCF) have been shown to have significant reducibility when cycling temperature and oxygen partial pressure of the environment [1]. The combined reducibility and heat of the oxidation and reduction reactions with the sensible change in temperature of the material leads to specific energy storage values approaching 700 kJ kg −1 . A potential thermochemical energy storage system configuration and modeling strategy is reported on, leading to a parametric study of critical operating parameters on the TCES subsystem performance. For the LSCF material operating between 500 and 900°C with oxygen partial pressure swings from ambient to 0.0001 bar, system efficiencies of 68.6% based on the net thermal energy delivered to the power cycle relative to the incident solar flux on the receiver and auxiliary power requirements, with specific energy storage of 686 kJ kg −1 are predicted. Alternatively, only cycling the temperature between 500 and 900°C without oxygen partial pressure swings results in TCES subsystem efficiencies up to 76.3% with specific energy storage of 533 kJ kg −1 .

Electrical energy storage (EES) is an important component of the future electric grid. Given that no other widely available technology meets all the EES requirements, reversible (or regenerative) solid oxide cells (ReSOCs) working in both fuel cell (power producing) and electrolysis (fuel producing) modes are envisioned as a technology capable of providing highly efficient and cost-effective EES. However, there are still many challenges from cell materials development to system level operation of ReSOCs that should be addressed before widespread application. One particular challenge of this novel system is establishing effective thermal management strategies to maintain the high conversion efficiency of the ReSOC. The system presented in this paper employs a thermal management strategy of promoting exothermic methanation in the ReSOC stack to offset the endothermic electrolysis reactions during charging mode (fuel producing) while also enhancing the energy density of the stored gases. Modeling and parametric analysis of an energy storage concept is performed using a thermodynamic system model coupled with a physically based ReSOC stack model. Results indicate that roundtrip efficiencies greater than 70% can be achieved at intermediate stack temperature (∼680°C) and pressure (∼20 bar). The optimal operating conditions result from a tradeoff between high stack efficiency and high parasitic balance of plant power.

One potentially attractive application of solid oxide fuel cells (SOFCs) is for combined heat and power (CHP) in light commercial buildings. An SOFC-based CHP system can be employed to efficiently serve building thermal and electric loads, thereby lowering utility bills and offering many distributed generation benefits. It is often desirable to operate SOFCs in a predominately base load manner from a hardware viewpoint. However, systems in practice will experience some load dynamics during their lifetime and furthermore, optimal economic dispatch of CHP systems frequently recommends a load-following strategy. Thus, the present work is motivated by the need to understand the dynamic response capabilities of SOFC-CHP systems. Part-load performance and dynamic load-following capabilities of a 24 kW planar SOFC system for light commercial applications was investigated through computational modeling. The SOFC and balance-of-plant component models were implemented in gPROMS modeling software. The modeling strategy of each system component and associated transients are discussed. A dynamic SOFC channel-level model, which has been verified against experimental cell data, was integrated with additional balance-of-plant (BOP) component models consisting of a fuel reformer, tail gas combustor, turbomachinery, heat exchangers, and bypass valves. The performance of the system at part-load operation displays increases in electrical efficiency and decreases in CHP efficiency, as well as a more uniform PEN temperature profile. Modeling comparisons between the responses of systems consisting of either dynamic or steady-state BOP component models are reported. A fully dynamic system-level model displays anodic fuel depletion effects and waste heat recovery transients not captured by the steady-state models. The dynamics influence the ability of an SOFC system to load follow indicating when thermal and electric storage may be necessary.

A one-dimensional model of a high-temperature solid-oxide fuel cell (SOFC) stack contained in a geothermic fuel cell (GFC) assembly is presented. The GFC concept, developed by IEP Technology Inc., involves the harnessing of heat generated during SOFC stack operation for the liberation of oil and gas from oil shale. The first GFC prototype, designed and built by Delphi Automotive, LLC., is comprised of three 1.5-kW SOFC stacks housed in a stainless-steel casing. Hot exhaust gases exiting the stacks are directed out of the stack-containment vessel, rejecting heat to the surroundings before being exhausted above ground. The primary aims of this work are to develop modeling tools to (1) predict the stack electrochemical performance and (2) elucidate the thermal characteristics of the stack assembly during operation through modeling and simulation. Aspen Plus process-simulation software and an embedded electrochemical model are utilized to predict the temperature dynamics and the electrical output of the GFC stack. The stack performance is decomposed with a temperature-dependent Area Specific Resistance (ASR) obtained from analysis of experimental data from a single stack that was operated over a wide temperature range. Independent full-scale stack testing has enabled performance validation of the electrochemical model. Experimental data from the three-stack GFC assembly has been used to calibrate the thermal-modeling approaches and the external heat-rejection predictions. Simulation results for steady-state conditions under hydrogen fuel are presented and compared to experimental data from thermocouples on the GFC prototype. The model will be used to explore the interaction of the geothermic fuel cell with the oil-shale formation in which it is installed.

Fuels derived from biomass feedstocks are a particularly attractive energy resource pathway given their inherent advantages of energy security via domestic fuel crop production and their renewable status. However, there are numerous questions regarding how to optimally produce, distribute, and utilize biofuels such that they are economically, energetically, and environmentally sustainable. Comparative analyses of two conceptual 2000 tonne/day thermochemical-based biorefineries are performed to explore the effects of emerging technologies on process efficiencies. System models of the biorefineries, created using ASPEN Plus®, include all primary process steps required to convert a biomass feedstock into hydrogen, including gasification, gas cleanup and conditioning, hydrogen purification, and thermal integration. The biorefinery concepts studied herein are representative of ‘near-term’ (ca. 2015) and ‘future’ (ca. 2025) plants. The ‘near-term’ plant design serves as a baseline concept and incorporates currently available commercial technologies for all non-gasifier processes. The ‘future’ plant design employs emerging gas cleaning and conditioning technologies for both tar and sulfur removal unit operations. Gasifier technology employed in these analyses is centered on directly-heated, oxygen-blown, fluidized-bed systems. Selection of the gasifier pressurizing agent (CO 2 v. N 2 ) is found to be a key factor in achieving high hydrogen production efficiency. Efficiency gains of 8-percentage points appear possible with CO 2 capture using Selexol or Rectisol-type processes. A 25% increase in electric power production is observed for the ‘future’ case over the baseline configuration due to improved thermal integration while realizing an overall plant efficiency improvement of 2 percentage points. Exergy analysis reveals the largest inefficiencies are associated with the (i) gasification, (ii) steam and power production, and (iii) gas cleanup and purification processes.

SOFC systems with co-generation exhibit high overall efficiency. Fuel cell-based co-generation studies have typically focused on electricity and heat; pure hydrogen gas can also be generated in these systems as an energy co-product resulting in the combined production of heat, hydrogen, and power (CHHP). Co-locating a distributed generation SOFC CHHP plant with fueling stations for fuel cell vehicles enables use of lower scale (200 kg/day) hydrogen production and leverages the capital investment among all co-products, thereby lowering the unit cost of hydrogen and offering a potentially promising transition pathway to a hydrogen economy. This work focuses on the design and performance estimation of a methane-fueled 1 MW SOFC CHHP system operating at steady-state. System design and modeling are carried out employing Aspen Plus™ software where performance characteristics of the SOFC and the balance-of-plant are estimated from industry and literature sources. Analysis of the SOFC CHHP system indicates that the SOFC electrochemical performance is independent of the heat recovery and hydrogen production processes because the latter two subsystems are downstream of the SOFC power module. The system is configured such that it can preferentially produce hydrogen or low-temperature thermal energy (80 °C) as needed. Two methods of hydrogen purification and recovery from the SOFC tail-gas were analyzed: pressure swing adsorption (PSA) and electrochemical hydrogen separation (EHS). The recovered hydrogen is compressed to 425 bar for storage. The SOFC electrical efficiency at rated power is estimated at 48.1% (LHV) and the overall CHHP efficiency is 84.4% (LHV) for the EHS design concept. The amount of hydrogen recovery (85–90%) with EHS is higher than PSA for typical SOFC effluent gas compositions. The hydrogen separation energy requirement of 2.7 kWh/kg H 2 for EHS is found to be about three times lower than PSA in this system. Increasing the amount of hydrogen production can be independently controlled by flowing excess methane into the system, effectively decreasing SOFC fuel utilization yet still reforming the fuel to a hydrogen-rich syngas. A case study for hydrogen overproduction is given. Operating the system to produce excess hydrogen increases the efficiency for both hydrogen separation design concepts.

A techno-economic optimization study investigating optimal design and operating strategies of solid oxide fuel cell (SOFC) micro-combined heat and power (CHP) systems for application in U.S. residential dwellings is carried out through modeling and simulation of various anode-supported planar SOFC-based system configurations. Five different SOFC system designs operating from either methane or hydrogen fuels are evaluated in terms of their energetic and economic performance and their overall suitability for meeting residential thermal-to-electric ratios. Life cycle cost models are developed and employed to generate optimization objective functions which are utilized to explore the sensitivity of the life cycle costs to various system design and economic parameters and to select optimal system configurations and operating parameters for eventual application in single-family, detached residential homes in the U.S. The study compares the results against a baseline SOFC-CHP system that employs primarily external steam reforming of methane. The results of the study indicate that system configurations and operating parameter selections that enable minimum life cycle cost while achieving maximum CHP system efficiency are possible. Life cycle cost reductions of over 30% and CHP efficiency improvements of nearly 20% from the baseline system are detailed.