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To reduce carbon emissions, generation of electricity from combustion systems is being replaced by renewable resources. However, the most abundant renewable sources – solar and wind – are not dispatchable, vary diurnally and are subject to intermittency, and produce electricity at times in excess of demand (excess production). To manage this variability and capture the excess renewable energy, energy storage technologies are being developed and deployed such as battery energy storage (BES), hydrogen production with electrolyzers (ELY) paired with hydrogen energy storage (HES) and fuel cells (FCs), and renewable natural gas (RNG) production. While BES may be better suited for short duration storage, hydrogen is suited for long duration storage and RNG can decarbonize the natural gas system. California Senate Bill 100 (SB100) sets a goal that all retail electricity sold in the State must be sourced from renewable and zero-carbon resources by 2045, raising the questions of which set of technologies and in what proportion are required to meet the 2045 target in the required timeframe as well as the role of the natural gas infrastructure, if any. To address these questions, this study combines electric grid dispatch modeling and optimization to identify the energy storage and dispatchable technologies in 5-year increments from 2030 to 2045 required to transition from a 60% renewable electric grid in 2035 to a 100% renewable electric grid in 2045. The results show that, by utilizing the established natural gas system to store and transmit hydrogen and RNG, the deployment of battery energy storage is dramatically reduced. The required capacity for BES in 2045, for example, is 40 times lower by leveraging the natural gas infrastructure with a concomitant reduction in cost and associated challenges to transform the electric grid. • The transition to a hydrogen economy can benefit from systematic planning. • Natural gas power plants (NGPPs) facilitate a cost-effective transition. • A high penetration of renewable generation requires long duration storage. • NGPPs significantly reduce the required energy storage capacity. [ABSTRACT FROM AUTHOR]

Since 2003, the National Fuel Cell Research Center at the University of California, Irvine (UCI) has operated the first U.S. publicly accessible hydrogen refueling station (HRS). During this period, the UCI HRS supported all manufacturers in the early, pre-commercialization years of the fuel cell electric vehicle (FCEV). This paper describes and analyzes the performance of the UCI HRS during the first five years of FCEV commercialization, over which time the station has dispensed the most hydrogen daily in the California network. The station performance is compared to aggregate data published by NREL for all U.S. HRSs. Using the Hydrogen Delivery Scenario Analysis Model, typical daily refueling profiles are analyzed to determine the effect on HRS design. The results show different daily refueling profiles could substantially affect HRS design and ultimately the cost of hydrogen. While technical issues have been reduced, the compressor, dispenser, and fueling rate are areas for improvement. Image 1 • Most utilized hydrogen refueling station in early years of commercialization. • Daily refueling profiles affect HRS design and the cost of hydrogen. • Reliability challenges include the compressor, dispenser, and fueling rate. [ABSTRACT FROM AUTHOR]

High contributions of the electricity generation and transportation sectors to criteria pollutant and greenhouse gas emissions have resulted in an increased interest and shift towards low to non-carbon generation options such as renewable wind and solar, and alternative transportation options including plug-in electric vehicles. Since plug-in electric vehicles transfer the tailpipe emissions to the electric grid, it is important to study the interaction between the two sectors. In this paper, a previously developed spatially and temporally resolved unit commitment model is used to determine the dispatch schedule of resources with and without battery electric vehicles for 2050 in a fictitious balancing area located within the South Coast Air Basin of California. Cases studied include various charging profiles, penetration in light-duty fleet, imports mix, and grid dispatch strategies. Results of the analysis include average cost of electricity production, market clearing price, temporal production of individual generators, and emissions from electricity generation and the transportation sectors. The results show that deploying battery electric vehicles (1) has little impact on the average cost of electricity generation-maximum of $2.5 per MW h for the cases studied with 40% penetration in the light-duty fleet, (2) reduces the overall criteria pollutant emissions except for one case, and (3) results in a smoother load profile, reduces the use of peaking units, and reduces the average emission intensity of the grid through controlled off-peak charging. [ABSTRACT FROM AUTHOR]

• Integration of off-the-shelf GT into SOFC-GT hybrid. • Comparison of constant spool speed, variable spool speed and VIGV operation. • Investigation of surge margin. • Thermodynamic and economic performance evaluation. The thermodynamic and economic performance of a natural gas-fueled solid oxide fuel cell (SOFC)-gas turbine (GT) hybrid system with a commercial off-the-shelf GT is investigated. Until today, commercial GTs are primarily engineered for the direct use of energy dense fuels, such as natural gas, and the integration of commercial GTs into a SOFC-GT hybrid remains challenging. In this work technically feasible and economically viable GT operating modes are identified to gauge the technology's competitiveness on the free market. Steady state, full load operating conditions were established for various GT operating modes: I) constant spool speed operation, II) variable spool speed operation and III) partially closed compressor inlet guide vanes. For each GT operating mode, the performance was investigated over a range of SOFC fuel utilization factors, while considering physical constraints inside the SOFC, such as local temperature gradients in flow direction as well as overall cell temperature differences. The results of the thermodynamic evaluation served as inputs for the economic analysis of the SOFC-GT hybrid power plant. The results show that the integration of an off-the-shelf GT not only results in a significant derating of the GT, but also substantially impacts the SOFC operation, the main power producer in this SOFC-GT hybrid. To maximize the SOFC power output it is desirable operate the GT in a region of high air mass flow rates and low pressure ratios, which increases the number of stacks that can be accommodated and reduces the SOFC cooling requirement. The lowest costs of electricity are obtained at constant spool speed operation, while the highest efficiencies are reached at variable spool speed operation. Critical for the integration of off-the-shelf GTs, which historically have been designed for natural gas, is the surge margin. The largest surge margins are obtained by closing the compressor inlet guide vanes. Furthermore, higher SOFC fuel utilization factors are shown to increase the surge margin as the turbine firing temperature is decreased. [ABSTRACT FROM AUTHOR]

Solid oxide fuel cell (SOFC)–gas turbine (GT) hybrid systems can produce power at high electrical efficiencies while emitting virtually zero criteria pollutants (e.g., ozone, carbon monoxide, oxides of nitrogen and sulfur, and particulate matters). This study presents new insights into renewable hydrogen (RH2)-powered SOFC–GT hybrid systems with respect to their system configuration and techno-economic analysis motivated by the need for clean on-demand power. First, three system configurations are thermodynamically assessed: (I) a reference case with no SOFC off-gas recirculation, (II) a case with cathode off-gas recirculation, and (III) a case with anode off-gas recirculation. While these configurations have been studied in isolation, here we provide a detailed performance comparison. Moreover, a techno-economic analysis is conducted to study the economic competitiveness of RH2-fueled hybrid systems and the economies of scale by offering a comparison to natural gas (NG)-fueled systems. Results show that the case with anode off-gas recirculation, with 68.50%-lower heating value (LHV) at a 10 MW scale, has the highest efficiency among the studied scenarios. When moving from 10 MW to 50 MW, the efficiency increases to 70.22%-LHV. These high efficiency values make SOFC–GT hybrid systems highly attractive in the context of a circular economy as they outcompete most other power generation technologies. The cost-of-electricity (COE) is reduced by about 10% when moving from 10 MW to 50 MW, from USD 1976/kW to USD 1668/kW, respectively. Renewable H2 is expected to be economically competitive with NG by 2030, when the U.S. Department of Energy's target of USD 1/kg RH2 is reached. [ABSTRACT FROM AUTHOR]

Abstract: A high market value exists for an integrated high-temperature fuel cell-absorption chiller product throughout the world. While high-temperature, molten carbonate fuel cells are being commercially deployed with combined heat and power (CHP) and absorption chillers are being commercially deployed with heat engines, the energy efficiency and environmental attributes of an integrated high-temperature fuel cell-absorption chiller product are singularly attractive for the emerging distributed generation (DG) combined cooling, heating, and power (CCHP) market. This study addresses the potential of cooling production by recovering and porting the thermal energy from the exhaust gas of a high-temperature fuel cell (HTFC) to a thermally activated absorption chiller. To assess the practical opportunity of serving an early DG-CCHP market, a commercially available direct fired double-effect absorption chiller is selected that closely matches the exhaust flow and temperature of a commercially available HTFC. Both components are individually modeled, and the models are then coupled to evaluate the potential of a DG-CCHP system. Simulation results show that a commercial molten carbonate fuel cell generating 300kW of electricity can be effectively coupled with a commercial 40 refrigeration ton (RT) absorption chiller. While the match between the two “off the shelf” units is close and the simulation results are encouraging, the match is not ideal. In particular, the fuel cell exhaust gas temperature is higher than the inlet temperature specified for the chiller and the exhaust flow rate is not sufficient to achieve the potential heat recovery within the chiller heat exchanger. To address these challenges, the study evaluates two strategies: (1) blending the fuel cell exhaust gas with ambient air, and (2) mixing the fuel cell exhaust gases with a fraction of the chiller exhaust gas. Both cases are shown to be viable and result in a temperature drop and flow rate increase of the gases before the chiller inlet. The results show that no risk of cold end corrosion within the chiller heat exchanger exists. In addition, crystallization is not an issue during system operation. Accounting for the electricity and the cooling produced and disregarding the remaining thermal energy, the second strategy is preferred and yields an overall estimated efficiency of 71.7%. [Copyright &y& Elsevier]

To reduce greenhouse gases and air pollutants, new technologies are emerging to reduce fossil fuel usage and to adopt more renewable energy sources. As the major aspects of fuel consumption, power generation, transportation, and industrial applications have been given significant attention. The past few decades witnessed astonishing technological advancement in these energy sectors. In contrast, the residential sector has had relatively little attention despite its significant utilization of fuels for a much longer period. However, almost every energy transition in human history was initiated by the residential sector. For example, the transition from fuelwood to cheap coal in the 1700s first took place in residential houses due to urbanization and industrialization. The present review demonstrates the energy transitions in the residential sector during the past two centuries while portending an upcoming energy transition and future energy structure for the residential sector. The feasibility of the 100% electrification of residential buildings is discussed based on current residential appliance adoption, and the analysis indicates a hybrid residential energy structure is preferred over depending on a single energy source. Technical considerations and suggestions are given to help incorporate more renewable energy into the residential fuel supply system. Finally, it is observed that, compared to the numerous regulations on large energy-consumption aspects, standards for residential appliances are scarce. Therefore, it is concluded that establishing appropriate testing methods is a critical enabling step to facilitate the adoption of renewable fuels in future appliances. [ABSTRACT FROM AUTHOR]

With the inexorable depletion of fossil fuel and the increasing need to reduce greenhouse gas emissions, blending renewable fuels like biogas or renewable hydrogen into natural gas is of great interest. Due to various potential sources and low-carbon or even carbon-free properties, biogas and hydrogen are competitive energy carriers and promising gaseous fuels to replace pipeline natural gas in the future. From the perspective of end users and combustion device manufacturers, one of the major concerns is the influence of the renewable content on the combustion device performance. In addition, the upper limit of renewable gas content percentage in pipeline also interests policy makers and gas utility companies. Therefore, the present study is conducted to investigate the influence of renewable gas content on the operating performance of a residential room furnace. Evaluated combustion performance characteristics include ignition performance, blow-off/flashback limits, burner temperature and emissions (NO, NO 2 , N 2 O, CO, UHC, NH 3). The results show that 5% carbon dioxide and 15% (by volume) hydrogen can be added to natural gas separately without significant impacts. Above this amount, the risk of blow-off and flashback is the limiting factor. Generally speaking, carbon dioxide addition helps decrease NO X emission but increases CO emission. However, hydrogen addition up to the amounts studied here in has minimal impact on NO X and CO emissions. Image 1 • Ignition failure and flame blow-off occur when CO 2 addition exceeds 5% and 25%, respectively. • Flashback induced ignition failure occurs when H 2 addition exceeds 15%. • Steady state flashback occurs when H 2 addition exceeds 40% by volume. • CO 2 addition reduces burner material temperature and H 2 addition increases it. • CO 2 addition decreases NO X emission and increases CO emission; however, H 2 addition has minimal impact on either NO X or CO emissions. [ABSTRACT FROM AUTHOR]

Adding renewable hydrogen into natural gas pipeline would bring down the net gas C/H ratio and hence the CO 2 emissions. Also, it can help stabilize electric grids and maximize the renewable output of intermittent energy sources (solar, wind, etc.) via power-to-gas pathway. However, hydrogen differs in its chemical and physical characteristics (flammability range, flame speed, density, adiabatic flame temperature, energy content, etc.) than natural gas. Before transitioning to hydrogen admixing into pipelines, a general agreement on maximum hydrogen tolerance pertaining to end use (residential appliances) operation needs to be established. Focusing on the combustion performance of two representative models of storage water heaters (conventional and low-NO x) in California, this research addresses how much H 2 content in natural gas can be tolerated without loss of critical performance parameters with reliable operation. Characteristics like flashback, ignition delay, flame structure, and emissions (NO x , NO, CO, CO 2 , UHC, and NH 3) at different concentrations of H 2 admixed with natural gas is investigated. The present study shows <10% H 2 can be added to natural gas without any loss of efficiency for both the low-NO x and conventional storage water heater. This work also aims to provide a brief review of burner configuration and emission regulation pertaining to water heating owing to a gap in the literature. Image 1 • Mixtures of hydrogen and natural gas are tested on representative water heaters. • Up to 10% hydrogen added to natural gas has little impact on combustion performance and operability. • Instability (ignition delay/flashback) during re-ignition of the main burner flame to maintain tank temperature is the limiting factor. • The hydrogen injection limit is lower than that proposed in a previous study. • Adding hydrogen up to 30% has minimal impact on emissions. [ABSTRACT FROM AUTHOR]

With the increasing need to reduce greenhouse gas emission and adopt sustainability in combustion systems, injection of renewable gases into the pipeline natural gas is of great interest. Due to high specific energy density and various potential sources, hydrogen is a competitive energy carrier and a promising gaseous fuel to replace natural gas in the future. To test the end use impact of hydrogen injection into the natural gas pipeline infrastructure, the present study has been carried out to evaluate the fuel interchangeability between hydrogen and natural gas in a residential commercial oven burner. Various combustion performance characteristics were evaluated, including flashback limits, ignition performance, flame characteristics, combustion noise, burner temperature and emissions (NO, NO 2 , N 2 O, CO, UHC, NH 3). Primary air entrainment process was also investigated. Several correlations for predicting air entrainment were compared and evaluated for accuracy based on the measured fuel/air concentration results in the burner. The results indicate that 25% (by volume) hydrogen can be added to natural gas without significant impacts. Above this amount, flashback in the burner tube is the limiting factor. Hydrogen addition has minimal impact on NO X emission while expectedly decreasing CO emissions. As the amount of hydrogen increases in the fuel, the ability of the fuel to entrain primary air decreases. Image 1 • Flashback at ignition limits the amount of hydrogen that can be added to natural gas to ~25% by volume. • Hydrogen addition doesn't impact oven burner NO X emissions, but, decreases CO, as expected. • The cyclic operation of the oven leads to complex emissions behavior as a function of time. • Primary air entrainment of the mixtures is successfully predicted using Jones's correlation. [ABSTRACT FROM AUTHOR]

• A methodology to assess BEBs as a microgrid resiliency resource. • BEBs offer a compelling microgrid resiliency enhancement. • BEBs offer a flexible portfolio of microgrid Mobility Services+. • A BEB fleet can serve as a blackstart resource for a tripped prime generator. During a grid outage, microgrids can benefit from energy resources that enhance the reliability and resiliency of serving critical loads and overall protection. The present study develops a methodology to assess the efficacy of battery electric buses (BEBs) as a microgrid resiliency attribute during islanded operations, and applies the methodology to an existing 20 MW-class microgrid equipped with a fleet of 20 BEBs. Each BEB comprises 324 kWh of stored energy and can charge/discharge at 80 kW which translates to 1.6 MW and the potential of 6.48 MWh of stored power and energy respectively depending on the state-of-charge of each bus. For the application evaluated, the methodology reveals that a BEB fleet can serve as a viable resiliency and flexible energy resource for an islanded microgrid by enabling Mobility Services +, examples of which include (1) deployment to serve critical loads within the microgrid (e.g., an emergency control center, shelter, clinic), (2) deployment to serve critical loads outside the microgrid (e.g., a hospital, fire station, grocery store), and (3) service as a blackstart resource should the microgrid prime power generator trip. In the present case, the BEB fleet has the ability to support a microgrid emergency center for at least 16 h, and serve as a blackstart resource with a probability of 100% by a combination of parked BEBs and BEBs recalled from on route transit service. [ABSTRACT FROM AUTHOR]

Displacing pipeline natural gas with renewable hydrogen is a promising way to reduce the emission of carbon dioxide, which is a major greenhouse gas. However, due to significantly differing characteristics of hydrogen and natural gas, such as flame speed, adiabatic flame temperature and stability limits, the combustion performance of hydrogen/natural gas mixture differs from pure natural gas. From the perspective of residential end users, a key question is: how much hydrogen can be injected into the pipeline natural gas without influencing the performance of the residential burners? A representative cooktop burner is selected to study the influence of hydrogen addition on the combustion and cooking performance. Flashback limits, ignition time, flame characteristics, cooking performance, combustion noise, burner temperature, and various emissions (NO, NO 2 , N 2 O, CO, unburned hydrocarbon (UHC), NH 3) are evaluated for different levels of hydrogen addition. According to the experimental results, the combustion performance of the cooktop burner is not significantly affected with up to about 15% hydrogen addition by volume, which shows the feasibility of utilizing hydrogen on existing cooking appliances without any modification. The experiment methodologies and results in this study will serve as a reference for future test and emission regulation standards on domestic burners. • Hydrogen injection testing is conducted on a representative cooktop burner. • Up to 15% hydrogen added to natural gas has little impact on cooking performance and operability. • Flashback during ignition is the limiting factor for the amount of hydrogen added. • The hydrogen injection limit is significantly lower than that proposed in a previous study. [ABSTRACT FROM AUTHOR]

This work presents the atomization characteristics and dynamics of water-in-heptane (W/H) emulsions injected into a gaseous crossflow. W/H mixtures were tested while varying momentum flux ratios and aerodynamic Weber numbers. Different injector orifice diameters and orifice length-to-diameter ratios were used to test the generality of the results. The atomization properties of W/H mixtures were compared with properties of neat water and neat heptane to evaluate the effect of an emulsion on droplet sizing, cross-sectional stability and dispersion, and jet penetration depth. Liquid dynamics were extracted through analyzing instantaneous spray measurements and dynamic mode decomposition (DMD) on high-speed video recordings of the atomization processes. Correlations were proposed to establish preliminary relationships between fundamental spray processes and test conditions. These correlations allowed for emulsion behavior to be compared with neat liquid behavior. The use of emulsions induces greater spray instability than through using neat liquids, likely due to the difficulty in injecting a stable emulsion. Neat liquid correlations were produced and successfully predicted various spray measurements. These correlations, however, indicate that injector geometry has an effect on spray properties, which need to be addressed independently. The emulsions are unable to adhere to the neat liquid correlations suggesting that an increased number of correlation terms are required to adequately predict emulsion behavior. [ABSTRACT FROM AUTHOR]

• An introduction to combustion (Third edition) has errors in H 2 flammability range. • H 2 flammability range 0.14–2.54 in noted references should be corrected to 0.10–7.14. • Flashback or explosion could be induced if wrong H 2 flammability range was adopted. [ABSTRACT FROM AUTHOR]

Different configurations of a 100% renewable electricity system are possible, but not all are equally desirable in terms of the scale of material resources required to sustain them. This study compares different approaches for developing a 100% renewable electricity system on the basis of the material mass investment required to sustain their physical components. Electric grid modeling accounting for operational constraints is used to determine the scale of energy technology capacities required to achieve a 100% renewable electricity system using California as a representative example and translating those requirements to material mass requirements. Using a wind/solar/storage approach requires exponentially growing capacities of energy storage to meet operational needs and requires significant material mass investments. Material resource efficiency of the system is shown to be improved by maximizing the use of regional non-variable renewables to the extent possible within local capacity constraints. Alternatively, overbuilding the wind and solar capacity in excess of that needed to meet annual demand is also shown to improve material resource efficiency of the system. Overall, different approaches for meeting a 100% renewable electricity penetration are not equally desirable when material resource usage is considered. This should be taken into account in future energy system planning studies. [ABSTRACT FROM AUTHOR]

The pursuit of future energy systems that can meet electricity demands while supporting the attainment of societal environment goals, including mitigating climate change and reducing pollution in the air, has led to questions regarding the viability of continued use of natural gas. Natural gas use, particularly for electricity generation, has increased in recent years due to enhanced resource availability from non-traditional reserves and pressure to reduce greenhouse gasses (GHG) from higher-emitting sources, including coal generation. While lower than coal emissions, current natural gas power generation strategies primarily utilize combustion with higher emissions of GHG and criteria pollutants than other low-carbon generation options, including renewable resources. Furthermore, emissions from life cycle stages of natural gas production and distribution can have additional detrimental GHG and air quality (AQ) impacts. On the other hand, natural gas power generation can play an important role in supporting renewable resource integration by (1) providing essential load balancing services, and (2) supporting the use of gaseous renewable fuels through the existing infrastructure of the natural gas system. Additionally, advanced technologies and strategies including fuel cells and combined cooling heating and power (CCHP) systems can facilitate natural gas generation with low emissions and high efficiencies. Thus, the role of natural gas generation in the context of GHG mitigation and AQ improvement is complex and multi-faceted, requiring consideration of more than simple quantification of total or net emissions. If appropriately constructed and managed, natural gas generation could support and advance sustainable and renewable energy. In this paper, a review of the literature regarding emissions from natural gas with a focus on power generation is conducted and discussed in the context of GHG and AQ impacts. In addition, a pathway forward is proposed for natural gas generation and infrastructure to maximize environmental benefits and support renewable resources in the attainment of emission reductions. [ABSTRACT FROM AUTHOR]

After molecular nitrogen, nitrous oxide (N 2 O) is the second most abundant nitrogen compound in the atmosphere and its concentration is rising at rate of 0.26% yr −1 (0.7 ppb yr −1 ). In the troposphere N 2 O is a relatively stable compound, however it is reactive in the stratosphere, where it is destroyed by photolysis with ultraviolet radiation. While photolysis in the stratosphere removes this potent greenhouse gas from the atmosphere, subsequent reactions also destroy protective ozone. Hence N 2 O is both a greenhouse gas and an ozone depleting gas and its increasing levels in the atmosphere warrant further understanding of its sources, including combustion. Most research on combustion generated N 2 O has focused on emissions from solid and liquid fuels, since these fuels contain nitrogen bonded to their molecular structure (fuel-nitrogen). It has been shown that this fuel bound nitrogen can be oxidized into N 2 O under relatively low temperature conditions. To date, direct emissions of N 2 O from combustion of typical gaseous fuels (which have no fuel bound nitrogen) have not received attention due to the established link fuel nitrogen and N 2 O emission. This paper presents evidence of alternative mechanisms of N 2 O emissions that do not involve fuel bound nitrogen. Of particular interest are lean premixed flames widely used for current low NO x combustion systems. Measurements were made under different operational modes: Steady state, ignition, and lean blowoff. A variety of gaseous fuel mixtures without fuel nitrogen including natural gas were considered, including, biogas and natural gas with up to 70% H 2 added (by volume). The results indicate that combustion of these fuels can directly emit significant levels of N 2 O, in particular during transient events such as ignition and blowoff. Furthermore, steady state combustion of hydrogen enriched natural gas flames (which can be operated at very lean conditions due to the stabilizing effects of hydrogen), can also lead to the direct emissions of N 2 O. [ABSTRACT FROM AUTHOR]

Historically, gas turbines (GTs) have been engineered for natural gas applications and costs are commonly estimated on a $/kW basis. However, when studying advanced power systems such as solid oxide fuel cell-GT hybrids or other unconventional applications, this commonly used cost basis cannot accurately predict the GT cost under these novel operating conditions, which ultimately leads to inaccurate economic evaluations of the entire power system. In this study, a parametric cost estimation approach has been utilized to identify the main cost drivers based upon the GT's on-design operating condition: I) GT air mass flow rate, II) GT compression ratio and III) GT turbine inlet temperature. Based on these characteristics, a GT cost correlation has been derived which is able to predict the GT genset price with an accuracy level of R2 = 97.5%. [ABSTRACT FROM AUTHOR]

Here we translate the impacts of climate change on hydropower generation, and discuss implications on greenhouse gas (GHG) emissions and operation in California. We integrate a model of major surface-water reservoirs with an electric grid dispatch model, and perturb it by projected runoff based on representative concentration pathways (RCP4.5 and RCP8.5). Results show that climate change and variability is expected to decrease the average annual hydropower generation by 3.1% under RCP4.5, but have negligible impact under the RCP8.5. Model simulations indicate more inflow, caused by more future extremes, in the future that does not necessarily translate to more energy production because of reservoir spillage of water. While overall volume of future available water for energy production may be similar or higher, the delivery of this volume is expected to be significantly more variable in the future climate than the historical average, which has many implications for hydropower generation. Our results show that the expected changes in future climate leads to increases in grid GHG emissions, load-following capacity, fuel usage, and costs for the RCP4.5 due to generation shortfall, and very slight increases in the same metrics for the RCP8.5 case due to variability causing decreased efficiencies in load-following power plants. [ABSTRACT FROM AUTHOR]

Substantial changes need to occur in the electricity generation sector in order to address greenhouse gas and urban air quality goals. These goals, combined with increasing energy prices, have led to elevated interest in alternative, low to zero carbon and pollutant emission technologies in this sector. The challenge is to assess the impacts of various technologies, policies, and market practices in order to develop a roadmap to meet energy and environmental goals. To this end, a spatially and temporally resolved resource dispatch model is developed that simulates an electricity market while taking into account physical constraints associated with various components of an electricity grid. Multiple technology simulation modules are developed to provide inputs to the model. The model is used to design a market-based grid, and to develop and evaluate different dispatch strategies. To maintain the system cost at acceptable levels and reduce emissions, the results reveal that the best approach is a combination of economic and environmental dispatch strategies. The methodology and the tools developed provide a means to examine various aspects of future scenarios and their impacts on different sectors, and can be used for both decision making and planning. [ABSTRACT FROM AUTHOR]

Converting abundant fossil resources of coal to alternative transportation fuels is a promising option for countries heavily dependent on petroleum imports if plants are equipped with carbon capture for sequestration and cofed with biomass (30% by weight of the total feed on a dry basis), an essentially carbon neutral fuel, without penalizing the process economics excessively. A potential exists to improve both thermal efficiency and economics of such plants by taking advantage of the synergies of coproducing electricity using advanced technologies under development. Three types of transportation fuels are considered. Fischer–Tropsch (F–T) liquids consisting predominantly of waxes could be processed in existing refineries while displacing petroleum and the refined products introduced into the market place at the present time or in the near term without requiring changes to the existing infrastructure. Ethanol could potentially serve in the not so distant future (or phased in by blending with conventional liquid fuels). Hydrogen which could play a dominant role in the more distant future being especially suitable to the fuel cell hybrid vehicle (FCHV). Two types of coal along with biomass cofeed are evaluated; bituminous coal at $42.0/dry tonne, lignite at $12.0/dry tonne, and switchgrass at $99.0/dry tonne. The calculated cost for F–T liquids ranged from $77.8/bbl to $86.6/bbl (or $0.0177 to 0.0197/MJ LHV) depending on the feedstock, which is comparable to the projected longer term market price of crude oil at ∼$80/bbl when supply and demand reach a new equilibrium [Lafakis. Moody’s Analytics. < http://money.cnn.com/2015/01/09/investing/oil-price-bottom/index.html > (accessed on 12.01.15)] [32] (or ∼$0.0172/MJ LHV). It should be noted, however, that F–T liquids contain no sulfur or nitrogen compounds and no inorganics. The calculated cost of fuel grade ethanol ranged from $4.84 to 4.91/gal (or $0.0566 to 0.0582/MJ LHV), while the price of gasoline in the U.S. amounted to $0.0240 to 0.0279/MJ LHV when crude oil was at ∼$80/bbl. Ethanol coproduction may not appear to be as attractive as the other options at these scales, primarily due to the much lower plant efficiency. However, from a life cycle greenhouse gas emissions standpoint, ethanol produced with biomass cofeeding and CCS, have a lower carbon footprint than gasoline or diesel, especially when derived from petroleum. The calculated cost of hydrogen ranged from $1.87 to 2.13/kg (or $0.0156 to 0.0177/MJ LHV), which is significantly lower than the DoE announced goal of $3.00/kg in 2005. [ABSTRACT FROM AUTHOR]

Alternative vehicles must appropriately interface with the electric grid and renewable generation to contribute to decarbonization. This study investigates the impact of infrastructure configurations and management strategies on the vehicle–grid interface and vehicle greenhouse gas reduction potential with regard to California's Executive Order S-21-09 goal. Considered are battery electric vehicles, gasoline-fueled plug-in hybrid electric vehicles, hydrogen-fueled fuel cell vehicles, and plug-in hybrid fuel cell vehicles. Temporally resolved models of the electric grid, electric vehicle charging, hydrogen infrastructure, and vehicle powertrain simulations are integrated. For plug-in vehicles, consumer travel patterns can limit the greenhouse gas reductions without smart charging or energy storage. For fuel cell vehicles, the fuel production mix must be optimized for minimal greenhouse gas emissions. The plug-in hybrid fuel cell vehicle has the largest potential for emissions reduction due to smaller battery and fuel cells keeping efficiencies higher and meeting 86% of miles on electric travel keeping the hydrogen demand low. Energy storage is required to meet Executive Order S-21-09 goals in all cases. Meeting the goal requires renewable capacities of 205 GW for plug-in hybrid fuel cell vehicles and battery electric vehicle 100s, 255 GW for battery electric vehicle 200s, and 325 GW for fuel cell vehicles. [ABSTRACT FROM AUTHOR]

The increasing demand on electric grids to support high penetrations of intermittent renewables, enhance power quality, increase reliability and resiliency, and provide ancillary services, is leading to local power generation on both sides of the meter. This paper describes the potential attributes of deploying 10–100 MW scale clusters of fuel cells installed at distribution substations to enable electric grid support through the provision of baseload and various levels of load following services. Such deployments, referred herein as Transmission Integrated Grid Energy Resource (TIGER) Stations, can also contribute to achieving air quality and climate goals through several high value attributes including high efficiency, ultra-low pollutant emissions, and near zero acoustic emissions. To quantitatively assess these benefits, a 5 GW deployment of TIGER Stations in the California electric system was analyzed using the Holistic Grid Resource Integration and Deployment (HiGRID) model at 33%, 43%, and 50% renewable penetration. The analysis establishes that (1) TIGER Stations have the potential to reduce carbon emissions and NO x emissions even when operated as baseload systems, and (2) TIGER Station load following capability is important for continued carbon emission reductions at higher renewable penetrations. Additional features of TIGER Stations, such as heat recovery or hybrid cycles, will further increase the attributes of TIGER Stations. [ABSTRACT FROM AUTHOR]

Abstract: The hybridization of gas turbine technology with high temperature fuel cells represents an ultra-high efficiency, ultra-low emission, fuel flexible power generation platform. The performance of past prototypes has been limited by marginal compatibility of the two primary sub-systems. This paper addresses the challenge of selecting compatible hardware by presenting a simple and robust method for bespoke hybrid system design and off-the-shelf component integration. This is the first application of detailed, spatially resolved, physical models capable of resolving off-design performance to the integration analysis of FC–GT hybrids. Static maps are produced for both turbine and fuel cell sub-systems that readily evaluate the compatibility and hybrid performance. Molten carbonate and solid oxide fuel cells are considered for hybridization with recuperated micro-turbines and larger axial flow gas turbine systems. Current state-of-the-art molten carbonate technology is shown to pair well with present micro-turbine technology in an FC bottoming cycle design achieving 74.4% LHV efficiency. Solid oxide technology demonstrates remarkable potential for integration with larger scale axial turbo-machinery to achieve greater than 75% LHV efficiency. This performance map technique closely matches results from detailed integrated hybrid system analyses, and enables quick determination of performance requirements for balance of plant design and optimization. [Copyright &y& Elsevier]

Abstract: Fuel cell gas turbine hybrid systems have achieved ultra-high efficiency and ultra-low emissions at small scales, but have yet to demonstrate effective dynamic responsiveness or base-load cost savings. Fuel cell systems and hybrid prototypes have not utilized controls to address thermal cycling during load following operation, and have thus been relegated to the less valuable base-load and peak shaving power market. Additionally, pressurized hybrid topping cycles have exhibited increased stall/surge characteristics particularly during off-design operation. This paper evaluates additional control actuators with simple control methods capable of mitigating spatial temperature variation and stall/surge risk during load following operation of hybrid fuel cell systems. The novel use of detailed, spatially resolved, physical fuel cell and turbine models in an integrated system simulation enables the development and evaluation of these additional control methods. It is shown that the hybrid system can achieve greater dynamic response over a larger operating envelope than either individual sub-system; the fuel cell or gas turbine. Results indicate that a combined feed-forward, P–I and cascade control strategy is capable of handling moderate perturbations and achieving a 2:1 (MCFC) or 4:1 (SOFC) turndown ratio while retaining >65% fuel-to-electricity efficiency, while maintaining an acceptable stack temperature profile and stall/surge margin. [Copyright &y& Elsevier]

Highlights: [•] Advanced technologies and their integrations for H2 coproducing IGCCs are identified. [•] HHV and moisture% of feedstock have significant effects on plant performance. [•] Net equivalent power efficiencies of coproducing IGCCs range from 35% to 38%. [•] Thermal performance of identified H2 coproducing IGCCs are competitive with SMR H2 plants. [•] Cost of produced H2 ranges from $1.42/kg to $2.77/kg depending on feedstock. [ABSTRACT FROM AUTHOR]

Abstract: Plug-in electric vehicles (PEVs), including plug-in hybrid electric vehicles (PHEVs) and battery electric vehicles (BEVs), have the potential to improve the energy and environmental landscape of personal transportation, but face a hurdle of access to charging infrastructure. Additionally, the types, locations, and quantities of electric vehicle supply equipment (EVSE) that will be required are not well established. This study investigates the charging infrastructure requirements from the perspective of PEV operating cost and BEV feasibility. California was selected as the research region and PEV parameters were selected based on the early deployed vehicles available in the emerging commercial market. To minimize operating cost, an optimal charging strategy based on 24 h travel patterns is proposed. Results indicate that charging time strategy is the most important factor in reducing PEV operating cost while greater numbers of charging locations provide diminishing benefits for PHEVs. Higher charging power capability, combined with an acceptable charging time strategy offer only slight benefits for PHEVs, but charging power is an important factor in increasing BEV functionality and decreasing public charging requirements. The approximation of the electric vehicle supply equipment (EVSE) needed at different types of locations (e.g., home, work place, shopping) is proposed based on an optimal charging strategy. [Copyright &y& Elsevier]

To increase reliability, resiliency, and overall efficiency, distributed generators are being deployed at sites including hotels, hospitals, and data centers. This study provides a novel evaluation of the operational and economic performance of a megawatt-class high-temperature fuel cell (HTFC) cogeneration plant coupled to a 200RT absorption chiller. With unique access to high-resolution data, comprehensive analyses are conducted to assess both the plant operational and, combined with electric utility data, economic performance including identifying the operational parameters that most affect economic performance. The analyses reveal the challenges in achieving viable operational and economic performance of distributed generators, the difficulty of acquiring detailed operational data, and the complex and varying array of electric utility rates and demand charges. The fluctuation in electric and natural gas utility rates represent the largest impact on the economic performance. While the fuel cell can reduce the monthly demand charge that would otherwise be applied, a trip of the fuel cell can result in a monthly demand charge and compromise the financial viability of the plant. In the present case, the first four years of operation resulted in a net loss rather than the savings expected. Strategies to yield a net gain are presented. [Display omitted] • Multi year operational and economic performance of a commercial 1.4 MW HTFC/Chiller. • Detailed sensitivity analysis of factors affecting operational performance. • Projection of future economic performance with measures for improvement. • Results that inform the design and commercial deployment of HTFC/Chiller systems. [ABSTRACT FROM AUTHOR]

• Wildfires contribute 92 % of Naphthalene, 82 % of PM_PAH emissions in study period. • Model performance improved for PM2.5 and PAHs prediction with proposed method. • PM_PAH impacts broader areas, while naphthalene's effect is localized to fire zones. • In fire season, 32 % (particles) and 10 % (gas) of PAH exposure linked to wildfires. In recent years, wildfires in California have increased in frequency and intensity due to climate change and prolonged drought. The air pollutants released by wildfires cause significant health consequences, among which polycyclic aromatic hydrocarbons (PAHs) are particularly toxic. Estimating PAH emissions from wildfires is challenging due to variability in vegetation types. In this study, we estimate PAH emission rates across California at a high resolution, based on laboratory-measured PAH emission rates from 22 different vegetation types and detailed vegetation mapping. By combining these estimates with biomass burning data from the NCAR Fire Inventory, the Community Multiscale Air Quality Modeling System simulates PAH concentrations for the 2017 fire season. The modeling results compare favorably to measurements from three PAH monitoring sites in California. The peak PAH emissions from wildfire events are up to be 80 times higher in the gas phase and 32 times higher in the particle phase compared to a case without fire emissions. The population-weighted PAH concentrations from the fire case (0.053 µg/m3) are 47 % higher compared to a non-fire case (0.036 µg/m3) in the particle phase and 11 % higher in the gas phase (9.82 ppt compared to 8.83 ppt) during the study period. While highly depended on the meteorological condition, the simulated spatial distribution indicates that gas-phase PAHs are less likely to travel long distances from the fire source and are prone to aging into the particle phase during transport. Consequently, populations are more likely to be exposed to particle-phase PAHs during wildfire events. This finding has important implications for understanding the health impacts of wildfire-induced PAH concentrations, as particle-phase PAHs may have different toxicological effects compared to gas-phase PAHs. [ABSTRACT FROM AUTHOR]

SUMMARY Quantifying the severity of the intermittencies in solar irradiation is important for (i) understanding the potential impacts of high solar power penetration levels on the electric grid and (ii) evaluating the need for technologies that may be necessary to complement solar power in order to balance the electric grid. This study uses a spectral method to distinguish between cloud-induced and diurnal cycle-induced transients and to quantify the severity of intermittencies occurring over a range of timescales. The method is used to quantify variability between specific sites as well as to evaluate the sensitivity of solar power variability to spatial diversification of the solar farm portfolio. Results indicate that increasing the spatial diversity of the solar farm portfolio reduces the magnitude of the fluctuations in power output as a fraction of the total system capacity. This behavior is associated with two forces: (i) a reduction in the influence of fluctuations occurring at an individual site on the total profile and (ii) should the sites in question be sufficiently spaced apart, the fluctuations in solar irradiation that each site exhibits are uncorrelated and do not generally add up in tandem at short timescales. These effects reduce the degree of uncertainty and variability associated with solar farm output and demonstrate a reduction in the maximum magnitude of solar power fluctuations for a given solar penetration level. The rate of increase of the maximum solar power deviation from the 1-h average associated with increases in desired solar penetration level decreases in an inverse exponential manner with the number of sufficiently spaced sites composing the solar farm portfolio. These results imply that a lower amount of regulation or energy storage capacity is needed to regulate solar intermittency if solar installations and the accommodating transmission infrastructure are designed and operated appropriately. Copyright © 2012 John Wiley & Sons, Ltd. [ABSTRACT FROM AUTHOR]

Abstract: This work builds upon previous high temperature fuel cell (HT-FC) modeling studies, capturing both steady state performance and transient behavior of HT-FC stacks by merging simplified dimensional aspects of a planar fuel cell stack with first principles physical modeling. Dynamic simulations are developed that spatially resolve fluctuations in temperature, pressure and concentration distributions during transient operation. A significant portion of the heat transfer occurs prior to and after the air passes over the electrochemically active portions of the cell, justifying additional heat transfer pathways from the stack to the air in order to accurately characterize the thermal transients and temperature distributions in the HT-FC stack. The highly configurable MatLab-Simulink® model developed can simulate both solid oxide and molten carbonate fuel cells utilizing either direct or indirect internal reforming. The perturbation response characteristics of the dynamic model to load, fuel flow, air flow and composition perturbations are discussed, and control strategies are introduced that minimize temperature fluctuations. Analysis indicates air flow and inlet temperature controls are sufficient to control average temperature and average internal temperature gradients. Internal heat transfer dynamics substantially change the spatial temperature distribution and local temperature gradients during typical operating conditions and perturbations. [Copyright &y& Elsevier]

Autoignition delay times of mixtures of a/kanes and natural gas were studied experimen- tally in a high pressure and intermediate temperature turbulent flow reactor Measure- ments were made at pressures between 7 atm and 15 atm and temperatures from 785 K to 935 K. The blends include binary and ternary mixtures of methane, ethane, and propane along with various natural gas blends. Based on these data, the effect of higher hydro- carbons on the ignition delay time of natural gas type fuels at actual gas turbine engine conditions has been quanti~fied. While the addition of higher hydrocarbons in quantities of up to 30% was found to reduce the ignition delay by up to a factor of 4, the delay times were still found to be greater than 60 ms in all cases, which is well above the residence times of most engine premixers. The data were used to develop simple Arrhenius type correlations as a function of temperature, pressure, and fuel composition for design use. [DOl: 10.1115/1.4001981] [ABSTRACT FROM AUTHOR]

The emissions of liquid-fuel fired gas turbine engines are strongly affected by the fuel preparation process that includes atomization, evaporation, and mixing. In the present paper, the effects of fuel atomization and evaporation on emissions from an industrial gas turbine engine were investigated. In the engine studied, the fuel injector consists of a coaxial plain jet airblast atomizer and a premixer which consists of a cylindrical tube with four mixing holes and swirler slits. The goal of this device is to establish a fully vaporized, homogeneous fuel/air mixture for introduction into the combustion chamber and the reaction zone. In the present study, experiments were conducted at atmospheric pressure and room temperature as well as at actual engine conditions (0.34 MPa, 740 K) both with and without the premixer. Measurements included visualization, droplet size, and velocity. By conducting tests with and without the premising section, the effect of the mixing holes and swirler slit design on atomization and evaporation was isolated. The results were also compared with engine data and the relationship between premixer performance and emissions was evaluated. By comparing the results of tests over a range of pressures, the viability of two scaling methods was evaluated with the conclusion that ,spray angle correlates with fuel to atomizing air momentum ratio. For the injector studied, however, the conditions resulting in superior atomization and vaporization did not translate into superior emissions performance. This suggests that, while atomization and the evaporation of the fuel are important in the fuel preparation process, they ate of secondary importance to the fuel/air mixing prior to, and in the early stages of the reaction in, governing emissions. [ABSTRACT FROM AUTHOR]

The second-law efficiency is proposed for measuring and comparing the performance of electrochemical processes. It measures how close the process approaches a reversible process. Other definitions of efficiency found in the literature based on the first law of thermodynamics can generate efficiency values that are >100% for certain systems depending on whether the change in entropy for the overall chemical reaction involved in the process is positive or negative. Such efficiency values are misleading while making it difficult to compare processes that absorb or release significant quantities of thermal energy. Use of the proposed efficiency which is within the frame work of the second law of thermodynamics, can reach 100% only in the limit of a reversible process and will always stay <100% whether the entropy change is positive or negative. Furthermore, it accounts for the quality of thermal energy added to or removed from the system and thus provides a more consistent way of comparing different types of electrochemical devices. This consistency will allow better comparison of performance on a widespread basis, i.e., between groups working on distinct electrochemical systems. [Copyright &y& Elsevier]

Climate change mitigation requires developing zero-carbon, highly renewable energy systems, which require technologies to capture excess renewable electricity such as energy storage. Endeavoring to capture all available excess renewable electricity, however, may require large energy storage capacities and costs. This study therefore investigates how much curtailment is cost-optimal to allow in developing fully decarbonized electricity systems, using compliance with California's Senate Bill 100 goal as a representative case study. We combine electric grid dispatch modeling with an optimization approach for selecting the composition of energy storage technologies to capture excess renewable electricity to minimize overall system costs. We found that overbuilding cheap wind and solar and allowing the curtailment of excess renewable electricity equivalent to 25–43% of the total annual electric load resulted in the lowest cumulative systemwide cost for a fully decarbonized electricity system of about $1.8 trillion, spent between 2020 and 2045. Allowing no renewable curtailment results in significant battery requirements and a cumulative systemwide cost of $5.2 trillion spent between 2020 and 2045. Therefore, allowing some curtailment reduced the cost of building a fully decarbonized electricity system by a factor of 3 when the portfolio of technologies to capture and manage excess renewable electricity is carefully chosen. • Examined cost-minimal renewable curtailment levels for a zero-carbon grid. • Assessed cost-optimal technology mixes for harnessing excess renewable electricity. • Overbuilding renewable capacity is cheaper than vastly expanding energy storage. • Long duration storage is critical to minimize costs to build a zero-carbon grid. • Power-to-gas is well suited for long duration storage alongside batteries. [ABSTRACT FROM AUTHOR]

The thermodynamic performance of a solid oxide fuel cell (SOFC)-gas turbine (GT) hybrid system has been investigated at steady state operating conditions considering overall cell temperature differences and local thermal gradients inside the SOFC. The obtained simulation results served as input for the thermo-economic evaluation of the SOFC-GT hybrid. The system has been studied at two different operating voltages, various operating pressures, and fuel utilization factors. The results show that operating the system at higher fuel utilization factors and higher pressure ratios results in a substantially increased air flow requirement to maintain acceptable temperature differences and thermal gradients. The highest efficiency is obtained at the higher operating voltage of the two studied scenarios, a moderate pressure ratio of 5 bar and a moderate fuel utilization of 87.6%. However, the lowest cost of electricity is obtained at the lower operating voltage, the same pressure ratio and a lower fuel utilization compared to the highest efficiency case. • Using only GT exhaust gas recuperation achieves highest efficiency. • Pressure ratios around 5 bar achieve highest efficiencies. • Pressure ratios around 5 bar achieve lowest cost of electricity. • Fuel utilization around 85% achieves lowest cost of electricity. [ABSTRACT FROM AUTHOR]

Facilities such as ports that are associated with goods movement face challenges in managing energy requirements including growing demands, maintaining economic competitiveness, increasing efficiencies of operation, and improving the resiliency, reliability, and security of the energy supply. Furthermore, ports face pressure to meet environmental goals including reducing the emissions of both pollutants and greenhouse gases and increasing the levels of renewable sources. Within this framework, many port operators are pursuing the development of microgrids supported by self-generation including fuel cell systems. Given the breadth of energy requirements of ports, the range of fuel cell applications is an attractive resource for stationary power generation, motive power and fuel generation, and backup/auxiliary power in concert with base load power. This work involves a review of the literature, from a technical perspective, to assess microgrids and fuel cell systems at ports including comparison with combustion-based power distributed generation sources. Additionally, novel simulations are presented to provide insight into economic and emission considerations associated with fuel cell deployment in critical facilities. Important distinctions of fuel cells for ports include flexibility of size and fuel, low to negligible emissions, capability to operate in grid-forming mode, and high electric-only efficiencies. While combined cooling, heating, and power improves performance and should be pursued, the mismatch in port electrical and thermal loads is a potential barrier and increases the importance of high electric-only efficiencies of fuel cells. Tri-generation systems have the potential to maximize benefits with the production of hydrogen along with electricity and, if needed, heat. • Fuel cell systems can support microgrids at ports. • A critical facility is modeled and use of fuel cells in islanding is simulated. • Microgrids can provide necessary reliability and resiliency for ports operations. [ABSTRACT FROM AUTHOR]

The maximum firing temperature of a gas turbine (GT) is limited by material constraints. Critical for the operation of the GT is the blade metal temperature, which is impacted by the heat transfer from the combustor outlet gas to the blade surface. In this study, performance characteristics for an H-class-type GT have been established and two correlations for the change in the maximum permissible firing temperature as function of combustor outlet gas composition or flue gas composition and pressure ratio have been derived: (I) for detailed GT modeling with cooling flows and (II) for simplified GT modeling without specifying cooling flows. [ABSTRACT FROM AUTHOR]

This analysis applies a novel learning-curve methodology with uncertainty through Monte Carlo simulation to forecast market share of competing renewable fuel production technologies from 2025 through 2050. The analysis incorporates uncertainty in technology learning rate within Wright's Law, market rate of growth, and project-specific bidding to develop build-out scenarios for renewable hydrogen production capacity to serve the global market through 2050 with California as a proxy. Two major hydrogen production technologies are included: electrolyzers (with proton exchange membrane electrolytic cells as proxies) and thermochemical devices (with gasifiers as proxies). The method provides a quantitative foundation to forecasting technology shares in emerging sectors, overcomes the weakness of point estimates of relative cost that generally lead to binary behavior, and can support policy development and assessment of community impacts associated with the large-scale facility build-out needed to serve the growing demand for renewable hydrogen in transportation and other applications. Results show that biomass gasifiers are the dominant technology in the early market but the higher learning rate of electrolyzers and long-term trend of price decline for renewable electricity leads to equal shares for new installations by the mid-term and eventually to electrolyzers having the dominant share of new facilities. Electricity, biomass, and initial gasifier technology costs are the three primary factors impacting 2050 renewable hydrogen market composition. • Novel method to project fuel production technology shares with uncertainty proposed. • Methodology recognizes variability in technology cost at a point in time. • Methodology overcomes single winner outcome of point estimates of future cost. • Electrolyzers are projected to increase in market share continually from 2025. • Feedstock and initial gasifier costs impact 2050 market composition the most. [ABSTRACT FROM AUTHOR]

• Large-scale fuel cells were deployed to support constrained transmission systems. • A combined active/reactive power injection seems ideal for voltage regulation. • Placing TIGER on the lowest voltage bus achieved greater grid benefits. • TIGER deployment enhanced the overall system steady-state voltage stability. This paper estimates operational benefits and opportunities for utility-scale, distributed generation resources, called Transmission Integrated Grid Energy Resource (TIGER) stations herein, to support the electric power grid. Efficient, near-zero-emissions, high-temperature Fuel Cells fed by natural gas, operate as the generation source. For analysis, we use the real-world case of the transmission system in Southern California associated with the closure of the San Onofre nuclear power plant, which triggered the need for supplemental generation support and grid reliability. In this context, TIGER stations emerge as an opportunity to enhance grid characteristics. Steady-state power flow simulations were carried out for different TIGER station deployments. Results show that TIGER stations reduce line losses and provide local voltage support. The installation of only three TIGER stations operating at 70 MW/70 MVAR, or 100 MVAR each, was able to maintain voltage throughout at 0.98 p.u. or above when it otherwise had dropped to near 0.92 p.u. when the 2.0 GW nuclear plant went offline. The best TIGER placement was proven to always be at the weakest point in the system (at the end of the circuit, at the lowest voltage bus) as opposed to being distributed across nearby buses. [ABSTRACT FROM AUTHOR]

• SOFC cost have been analyzed with respect to production scale. • Cost minimum for SOFC length around 15–20 cm. • Increasing rib width is a cost-effective way to reduce thermal stress. • Air utilization of 45% is most cost effective. Typical operating parameters of a SOFC-GT hybrid system have been established to study the influence of SOFC-cell design variables such as cell length, rib width, interconnect thickness, and operating variables such as degree of pre-reforming and air utilization, upon thermal cell management and economics. Various SOFC production scales are being considered. Fuel utilization, air utilization and operating voltage were held constant while the number of cells was adjusted to meet the utilization specifications. Based upon the particular cell design and number of cells, the cost of the stacks has been established which is then converted to specific cost in $(2019)/kW DC. Findings show that in co-flow SOFCs specific costs can be effectively reduced by maximizing the cell width/number of parallel channels without impacting current density and thermal cell management. The cost optimum for the cell length was found to be in the range of 15–20 cm. While overall temperature differences were reduced in shorter cells, local gradients were reduced in longer cells. Increasing the rib width offers a cost-effective solution for reducing thermal gradients in the cell. Air utilization reaches a cost optimum around 45% and the operating voltage shows that lower cell voltages increase overall temperature differences and local thermal gradients while reducing specific SOFC cost. [ABSTRACT FROM AUTHOR]

• Infrastructure and emissions of conventional and alternative vehicles are analyzed. • Alternative vehicle fuel supply chains dictate GHG and pollutant emission levels. • Hybrid Electric and Plug-In Hybrid Electric Vehicles bridge to alternative vehicles. • Range extended Plug-In Electric Vehicles have relatively low infrastructure costs. • Plug-In Fuel Cell Electric Vehicles expedite the transition to alternative vehicles. The evolution of alternative vehicles is leading to an evolution in fuel, from electricity to hydrogen, and the associated fueling infrastructure. Using California as an example and a variety of tools (e.g., vehicle and electric grid simulation, travel surveys, census data, and GIS analyses), fueling supply chain and dispensing scenarios are evaluated and compared for conventional internal combustion vehicles (ICVs), vehicles bridging from conventional to alternative vehicles such as hybrid electric vehicles (HEVs) and plug-in hybrid electric vehicles (PHEVs), and alternative vehicles including battery electric vehicles (BEVs), fuel cell electric vehicles (FCEVs), and plug-in fuel cell electric vehicles (PFCEVs). When assessed for a 2050 timeframe, PFCEVs require less electric infrastructure compared to BEVs, and less hydrogen infrastructure compared to FCEVs. In addition, until 100% zero-emission fuel supply chains are achieved, PFCEVs reduce GHG and CAP emissions to a greater extent than BEVs and FCEVs. [ABSTRACT FROM AUTHOR]

Integrated gasification combined cycle (IGCC) power plant with dual-stage Selexol™ for carbon capture is compared to pressure swing adsorption (PSA)-based warm gas CO 2 capture. Capture with Selexol™ was limited to 83.4% due to high syngas CH 4 content while the efficiency was 31.11% HHV resulting in a 1st year cost of electricity (COE) of 148.6 $/MWh. Carbon capture can be increased to 88.6% and efficiency to 33.76% HHV with warm gas CO 2 removal. When holding the same carbon capture level as the Selexol™ case, efficiency is increased to 34.20% HHV and after further optimization of the water gas shift (WGS) reactors to 35.63% HHV leading to a lower COE of 127.2 $/MWh. Reaction kinetic models are developed and applied for optimization of WGS reactors to convert syngas CO to CO 2. Cost for warm gas carbon capture reduced to 47.5 $/tonne from 66.0 $/tonne for IGCC without carbon capture while CO 2 avoided cost reduced from 89.4 $/tonne to 54.3 $/tonne. Carbon capture cost dropped from 88.0 $/tonne to 72.7 $/tonne while the CO 2 avoided cost decreased from 112.2 $/tonne to 78.3 $/tonne over supercritical boiler plant without carbon capture. Furthermore, warm gas cleanup lowered the specific net water withdrawal/usage by 13.4%. • Thermo-economics of sub-bituminous coal TRIG™ IGCC with cold and warm gas cleanup. • Syngas desulfurization/decarbonization with Selexol™ versus ZnO sorbent/CO 2 PSA. • Shift reactor optimization using reaction kinetics and thermodynamic gas stability. • Selexol™ based IGCC efficiency of 31.11% resulted in electricity cost of $149/MWh. • Warm gas cleanup improved efficiency to 35.63% and electricity cost to $127/MWh. [ABSTRACT FROM AUTHOR]

Water resources are becoming scarce and climate change is exacerbating the stress on traditional water supplies. Thus, it is important to identify viable solutions to resolve tensions in the water energy nexus. One example is the use of transport membrane condensers (TMCs) to recover water as well as waste heat from flue gases with the aim to improve economics and to reduce the environmental impact of the industrial sector. In this work, the authors present a detailed 1D+1D TMC model and investigate the impact of three key membrane design parameters upon the water recovery rate. Sensitivity analyses of pore radius, membrane porosity and contact angle reveal that pore radii of smaller than 10 nm can substantially improve condensation rates due to the exponential vapor pressure dependency described by the Kelvin equation. Reducing the pore radius from 15 nm to 1 nm increases water recovery by over 74% in some of the study scenarios. Additionally, a higher membrane porosity is shown to increase water condensation rates. A higher porosity increases the number of pores on the surface, and thus, the driving force for mass transport. The results show an increase in water recovery of up to 7.7% per 10% porosity increase. The contact angle, which is related to the hydrophilicity of the membrane material, influences the formation of the meniscus inside the pore. Changes in the contact angle from a flat surface (90°) to 30° are shown to have a strong impact upon the water condensation rate. Furthermore, condensation flux improvements through the above-mentioned membrane design modifications are more pronounced in environments with low mass transport driving force due to the nature of the suction effect, which is governed by diffusion and convection transport laws. • Detailed transport membrane condenser modeling. • Simulation of flue gas water recovery. • Parametric study of membrane design parameters. [ABSTRACT FROM AUTHOR]

Due to the urgency of reducing greenhouse gases in the combustion process, low-carbon renewable gaseous fuels are needed to replace the pipeline natural gas. Hydrogen is a competitive sustainable energy source, and also a promising energy carrier because of its zero-carbon property and low molecular weight. This study analyzed the flame characteristics of a cooktop burner operating on different natural gas/hydrogen mixtures. As hydrogen percentage increasing from 0% to 75% in the fuel mixture, more reddish color was observed in the flame, which is against the scientific fact that hydrogen flame color is usually pale blue color or even invisible under normal light condition. Therefore, combustion experiments and electron microscopy analysis are conducted to track the source of the abnormal color in the flame. The results suggest that the abnormal reddish flame color is from hydrogen embrittlement on the storage and transport facilities. • Unexpected visible color is observed in hydrogen flame studies in the literature. • Hydrogen grade and filtration levels indicate fine particles may be responsible. • Electron microcopy ties the particles to high pressure cylinders supplying H 2. • The color emission does not seem to significantly alter combustion behavior. • The full impact of the contaminants on H 2 /Air flames remains to be quantified [ABSTRACT FROM AUTHOR]

Highlights • Computational fluid dynamics was applied to CO 2 adsorption and its auxiliary steps. • Adsorption model was incorporated into simulation by User Defined Functions. • Model successfully simulated cyclic process of adsorption in demonstration reactor. • Simulation showed only half of sorbent was effectively utilized for CO 2 adsorption. • Model is useful in correctly sizing adsorption bed and studying design tradeoffs. Abstract CO 2 adsorption is one of the warm gas cleanup technologies under development for integrated gasification combined cycle (IGCC) applications. Computational Fluid Dynamics (CFD) can be a practical and powerful tool for reactor design for and optimization of the CO 2 adsorption process. In this present work, CFD simulation was developed in commercially available ANSYS Fluent software and validated for solid sorbent CO 2 capture to investigate pressure swing adsorption (PSA) for CO 2 separation from syngas with all the auxiliary operating steps. The adsorption equilibrium and kinetics were incorporated into ANSYS by user defined functions (UDFs) for source terms in Navier–Stokes equations. The CFD model well predicted the CO 2 breakthrough curve and temperature change. It was shown that in demo reactor operation, at the end of adsorption step, only half of the sorbent was loaded with CO 2 , while most of the loaded CO 2 was released during the desorption step. Further optimization of sorbent packing and cycle operation can be done with assistance of this CFD model to maximize bed loading, and used to design the commercial size reactors. [ABSTRACT FROM AUTHOR]