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[Display omitted] • The pH-swing cold capture chloralkali process improves energy efficiency threefold over the benchmark process. • Integrating pH-swing cold capture chloralkali in eFuel synthesis moves most of the energy consumption to the electrolyzer. • We attain ∼ 76 % carbon capture efficiency and 79.5 % overall process efficiency. Renewable Fuels of Non-Biological Origin (RFNBOs, a.ka. "eFuels") are drop-in replacements for fossil fuels in the "hard-to-abate" sectors, and utilise existing distribution and storage infrastructure, but suffer from low synthetic efficiency. In particular, the low efficiency and high energy consumption of hydrogen synthesis by freshwater electrolysis remains a problem to be addressed. In the current study, we explore the potential of saltwater electrolysis (chloralkali) for the synthesis of eFuels generally, and specifically eMethanol. The study explores the use of chlorinated water in carbonate-loop pH-swing "cold capture" of carbon dioxide, and the resulting synergetic integration of the chloralkali process in eFuel syntheses. Doing so eliminates the high energy consumption of the calciner and the slaker of the benchmarked carbonate-loop thermal-swing method. It is replaced with a spontaneous chemical process in which chlorine is neutralized in the presence of carbonates. This allows the simultaneous solution of "The Chlorine Problem" of saltwater electrolysis, and a lower overall energy consumption of direct air capture when combined with green hydrogen synthesis. The only limitation on the comparison is that a large amount of carbon dioxide is over-captured when using chloralkali. That is, the ratio of hydrogen generated to carbon dioxide captured is fixed by the stoichiometry of chloralkali and not that of the eFuel. This results in an excess of carbon captured and thus a carbon-negative eFuel. We examine one configuration of secondary revenue and use it to inform the marginal cost of CO 2 capture. In the system proposed by Aeon Blue Technologies (ABT), carbon dioxide is absorbed into caustic according to the standard method. Hydrogen gas is produced in a standard chloralkali electrolyzer, along with caustic for the contactor, and chlorine. Water oxidation by chlorine gives the strong acid, hydrochloric acid, and the weak acid, hypochlorous acid, which react directly with wet carbonate to release CO 2. H 2 and CO 2 react in a methanol reactor to produce eFuel. H 2 is the limiting reagent for eFuel synthesis, giving an excess of cold captured CO 2. Thus, the current study underscores significant advancements in renewable fuel synthesis, particularly eMethanol, and evaluates the carbon capture and energy efficiency of a novel method. The simulation indicates that the marginal energy cost for a tonne of CO 2 is ∼ 184kWh. This gives ∼ 76 % theoretical carbon capture efficiency and an overall process efficiency of 79.5 % (approximately a threefold improvement over the benchmark). The authors are unaware of a comparable method. The overall system yields a tonne of carbon-neutral e-methanol (eMeOH) while capturing an additional 3 tonnes of carbon dioxide, which means the modelled process captures over 300 % more carbon dioxide than is released upon combustion of the eFuel. In summary, this research contributes valuable insights into carbon-negative eFuel production, representing a significant scientific step in sustainable fuel production. [ABSTRACT FROM AUTHOR]

Renewable energy technology-based power generation is considered to be environmentally friendly and to have a low life cycle greenhouse gas emissions footprint. However, the life cycle water footprint of renewable energy technology-based power generation needs to be assessed. The objective of this study is to develop life cycle water footprints for renewable energy technology-based power generation pathways. Water demand is evaluated through consumption and withdrawals coefficients developed in this study. Sixty renewable energy technology-based power generation pathways were developed for a comprehensive comparative assessment of water footprints. The pathways were based on the use of biomass, nuclear, solar, wind, hydroelectricity, and geothermal as the source of energy. During the complete life cycle, power generation from bio-oil extracted from wood chips, a biomass source, was found to have the highest water demand footprint and wind power the lowest. During the complete life cycle, the water demand coefficients for biomass-based power generation pathways range from 260 to 1289 l of water per kilowatt hour and for nuclear energy pathways from 0.48 to 179 l of water per kilowatt hour. The water demand for power generation from solar energy-based pathways ranges from 0.02 to 4.39 l of water per kilowatt hour, for geothermal pathways from 0.04 to 1.94 l of water per kilowatt hour, and for wind from 0.005 to 0.104 l of water per kilowatt hour. A sensitivity analysis was conducted with varying conversion efficiencies to evaluate the impact of power plant performance on water demand. Cooling systems used in power generation plants were also studied and include once-through, recirculating, dry, and hybrid cooling. When only the power generation stage is considered, hydroelectricity and nuclear power generation with once-through cooling systems showed the highest water consumption (68 l of water per kilowatt hour) and water withdrawals coefficients (178 l of water per kilowatt hour), respectively. [ABSTRACT FROM AUTHOR]

The key objective of this paper is to develop a benchmark for water demand coefficients of the complete life cycle of natural gas-fired power generation. Water demand coefficients include water consumption and water withdrawals for various stages of natural gas production as well as for power generation from it. Pathways were structured based on the unit operations of the types of natural gas sources, power generation technologies, and cooling systems. Eighteen generic pathways were developed to comparatively study the impacts of different unit operations on water demand. The lowest life cycle water consumption coefficient of 0.12 L/kW h is for the pathway of conventional gas with combined cycle technology, and dry cooling. The highest life cycle consumption coefficient of 2.57 L/kW h is for a pathway of shale gas utilization through steam cycle technology and cooling tower systems. The water consumption coefficient for the complete life cycle of cogeneration technology is in the range 0.07–0.39 L/kW h and for withdrawals ranged 0.10–14.73 L/kW h. [ABSTRACT FROM AUTHOR]

[Display omitted] • Clean electricity from the solar energy source. • Flat Plate solar collector is used as an input heat source to ORC. • MWCNT/R141b nanorefrigerant is used as an organic working fluid. • The Solar organic Rankine cycle system is evaluated energetically and exegetically. The principal purpose of the current investigation is to analyze the thermal performance of a small scale solar organic Rankine cycle (ORC). Herein, a flat plate solar collector (FPSC) was utilized to feed heat to ORC. A mathematical model formulated in Engineering Equation solver (EES), uses FPSC's experimental output to assess the thermal performance of ORC. To choose the most appropriate organic fluid for ORC, a preliminary study is conducted for the comparison of the performance of R141b with other organic fluids of previous research studies. In the preliminary analysis of this study, the MWCNT + WO 3 /water nanofluid is used in the solar collector for its performance enhancement and obtained a maximum thermal efficiency of 73.21% at 3 lpm and 1.5 vol%. Moreover, MWCNT/R141b nanorefrigerant is used as an organic fluid in ORC due to its enhanced thermophysical properties. The parametric analysis is also executed to compute the energetic and exergetic performance of ORC at different nanoparticle concentrations and volume flow rates. The parametric study demonstrated a significant increment from 16.30 to 24.82% and 9.03 to 15.33% in energy and exergy efficiency, respectively, for 0.5 vol% of nanorefrigerant and 3 lpm volume flow rate in collector when nanofluid volumetric concentration changes from 0.5 to 1.5 vol%. [ABSTRACT FROM AUTHOR]

[Display omitted] • A new concept of bifacial PV/PCM system developed and numerically investigated. • Bifurcated PCM enclosure design show higher thermo-electric performance. • New BIF PV/PCM system enhances the incident radiation utilization ability by 87%. • New BIF PV/PCM system overall system efficiency approaches to about 65% higher. A new concept of bifacial PV/PCM (BIF-PV/PCM) system with sandwiched thermal energy storage enclosure has been investigated that possesses 1.21 times power output density and 7.39 times total energy utilization density per unit land area compared to the conventional PV system. Based on the melting morphology and thermo-electric performance of the initially rectangular PCM enclosure, an optimized bifurcated non-rectangular design of the enclosure is proposed to enhance the incident radiation utilization ability by 87% more than a simple one PV/PCM system. Enhanced utilization of solar radiation manifests into 105% more melting compared to conventional PV/PCM system. With the strategic mirror reflection and bypassing the solar radiation towards the rear PV panel and strategic design of PCM enclosure to aid convection-driven melting, electric power output has been increased significantly (about 77%) compared to similar conventional PV/PCM system. The study revealed that overall system efficiency could approach about 74% if suitable strategies are adopted, as demonstrated in this paper. Results are discussed in terms of energy utilization efficiency, exergy efficiency, power conversion efficiency, tracking melting front morphology, and its effect on heat transfer characteristics, etc. This investigation has been carried out with the help of an experimentally calibrated numerical model that accurately mimics the melting morphology of PCM and other heat transfer characteristics of the system. The findings of this study would help design and develop a more efficient BIF-PV/PCM system to meet exponentially increasing energy needs. [ABSTRACT FROM AUTHOR]

[Display omitted] • Numerically investigated new designs of dual solar air heater with Trombe wall. • Bell-mouth inlet aids in improving hydraulic efficiency of the system. • Heating and cooling of space is faster in winter and summer respectively. • New system shows 2.5 times higher air mass flow rates with 142% exergy gain. • Dual Trombe-SAH has shorter payback period and could save tons of CO 2 annually. Trombe wall is one of the sustainable architectural designs in the building that offers significant opportunities for energy saving and contribute to the low green-house emissions. Naturally or buoyancy driven dual solar air heaters (SAH) are barely used in building sector with Trombe wall due to its low mass flow rates and low efficiency. In this paper, a new concept of integrating high flow naturally driven dual heating system of Trombe wall integrated with SAH has been numerically investigated, optimized and an efficient design configuration is proposed. Total seven independent configurations namely type-1 to 7 have been investigated wherein type-1 and 2 is SAH coupled with a vertical chimney, type-3 has SAH coupled with Trombe wall, and type-4 to 7 are SAH coupled with Trombe wall having bell-mouth inlet opening for improved hydraulic performance for rapid space heating. It is observed that if Trombe wall is integrated suitably with bell-mouth inlet, SAH along with chimney, it can significantly increase the mass flow rates of heated air by about 2.5 times the convectional design. It is also observed that with increase in mass flow rates, system shows significant exergy gain of 142% when compared to conventional design. Time needed to heat a given space from a specific initial temperature are also calculated using first law of thermodynamics with mass flow values taken from the model and compared with conventional design. It was noted that to heat a given space to a desired temperature, new system of dual SAH takes about 70% less time. The proposed coupled Trombe wall-SAH device has shorter payback period and could save tons of greenhouse gas emissions annually compared to the conventional fossil fuel-based heating systems. Thermal comfort of the occupant can be enhanced with dual SAH-Trombe wall system resulting in significant energy saving. [ABSTRACT FROM AUTHOR]

• Different reflector sizes at optimal configurations are experimentally investigated. • Enhancement factor of booster reflectors on PV panels is experimentally evaluated. • Experimental validation of an analytical model for augmented system is performed. • Enhancement electrical production of 17.8% with a reflector size of 2.5 m2 is noted. • Thermal and uneven illumination effect explain mismatch between model and experiments. In this paper the enhanced solar energy collection of a collector coupled with a flat booster bottom reflector is experimentally evaluated. The benefit provided by augmenting a PV panel with a specular reflector is then experimentally determined. The performances of an augmented PV arrangement and a conventional PV panel are compared. Five sizes of the reflector, at their optimal angular positions, aspect ratio and overhangs, are investigated as boosters of the PV panel. Several experiments have been carried out over the summertime for the reflector size, ranging from 0.3 m2 to 2.5 m2. The experimental enhancement factors (EFs) are further used to validate the analytical model, which includes an exact formulation of the shadowing and irradiating effects involved in the augmented system. This explorative investigation reveals experimental enhancement factor values in the range 6% − 17.8% and shows a good quantitative agreement with the predicted values. Moreover, the experimental profile reflects the simulated curve generated by the model. A detailed analysis demonstrates that the noted discrepancy between the simulated and experimental enhancement factor can be explained by the difference between the two PV panels conversion efficiencies that can arise when the two PV panels experience different operating temperature, and uneven illumination effect which were not explored in the model. [ABSTRACT FROM AUTHOR]

• Numerically investigated new designs of hybrid solar chimney power plant. • Performance discussed in terms of power generation via PV panel and wind turbine. • Significant impact of tapered collector and chimney divergence on power generation. • Integrating tapered collector with the divergent chimney was the best configuration. • Beyond 7% increase in PV panel efficiency and 200% in turbine power output. This paper examines the possibility of integrating a photovoltaic (PV) module in a hybrid solar chimney power plant (HSCPP). Since HSCPP is a greenhouse thermal buoyancy-driven system, the surrounding high temperature environment makes PV module temperature extremely high resulting in lower electrical conversion efficiency. Various design configurations of collector duct and solar chimney are investigated using an experimentally validated numerical model to study the PV panel cooling and turbine power output. The results show that turbine power output is sensitive to diverging the chimney up to maximum static pressure recovery limit while PV module shows marginal increase in electrical efficiency. Converging the collector duct alone shows worst turbine and PV module performance. However, in case of combine designs of converging duct and divergent chimney, considerable improvement of PV panel efficiency (about 7%) was observed. The results show that about 80% of the collector area measured from the chimney axis are the most effective region for cooling the PV module where consistent temperature drop of 10–12 °C was observed. A design map vs. PV panel efficiency has been shown charting future directions for designing such energy efficient hybrid solar chimney systems. [ABSTRACT FROM AUTHOR]

This paper interprets the energy flow from available primary fuel to end use in all of the provinces and territories in Canada for the year 2012 using Sankey diagrams. These flow charts illustrate energy production, imports, exports, and local consumption by economic sector, and quantify the amount of useful and rejected energy. The inflow and outflow values could help determine existing energy efficiencies and energy intensity improvement potential. The total energy available in the energy flow path for all of the provinces and territories is 27,494 PJ including imports. The diagrams clearly indicate that fossil fuels dominate Canada’s energy mix. Approximately 99% of the fuel in Alberta came from fossil sources in 2012 and approximately 76% of Canada’s energy came from fossil sources. Alberta produced the highest amount of available energy in Canada (11,986 PJ); the lowest came from the territories (72.7 PJ). Among the non-fossil generation, hydro-electricity dominated, followed by nuclear, wind, and biomass, respectively. The overall share of thermal-based generation (fossil-fuel, nuclear, and biomass) was found to be 37.1% of Canada’s produced electricity (2,222 PJ) in 2012. An analysis of rejected and useful energy indicated that the transport sector showed the poorest energy efficiency. This pictorial view of energy flow could help policy makers set targets for improving energy efficiency, select strategies for the reduction of greenhouse gases emissions, and help satisfy the vast global climate change challenges. [ABSTRACT FROM AUTHOR]

In this paper, a data-intensive cost model was developed for sensible heat, latent heat and thermochemical storage systems. In order to evaluate the economic feasibility of storage systems, five scenarios were developed depending on the method of storage. The five scenarios considered were indirect sensible heat, direct sensible heat using two tanks, direct sensible heat using one tank, latent heat and thermochemical storage. A Monte Carlo simulation was performed for all the scenarios to examine the uncertainty in the levelized cost of electricity when parameters such as solar multiple, plant capacity, storage duration, capacity factor, and discount rate are changed. The levelized cost of electricity ranges for individual scenarios are; 0.08–0.59 $/kWh for indirect sensible heat, 0.03–0.22 $/kWh for direct sensible heat using two tank, 0.02–0.16 $/kWh for direct sensible heat using one tank, 0.06–0.43 $/kWh for latent heat, and 0.22–1.19 $/kWh for thermochemical storage. The results indicate that when uncertainty is taken into account, the investment cost for thermochemical storage is clearly higher than other scenarios. This study will provide key information for industry and policy makers in decision making and in determining the economic viability of thermal energy storage systems. [ABSTRACT FROM AUTHOR]

• TEA of hydrogen production via photocatalytic water splitting was conducted. • Four earth abundant, active and stable photocatalysts were selected. • The LCOH ranges from 4.15 to 9.8 USD per kg of H 2 produced. • Capital investment and labour costs contribute the most, 75% of the total cost. • The system was scaled from lab to facility to produce 5 tonnes of H 2 per day. Photocatalytic water splitting using solar radiation is among the promising H 2 technologies. Titanium dioxide (TiO 2)- and carbon nitride (g-C 3 N 4)-based photocatalysts are the most widely used photocatalytic materials given their activity under visible light and their abundance. Several attempts have been made to improve the photocatalytic performance of these materials in terms of activity level, life span, response to visible radiation, and stability. However, the economic viability of the large-scale deployment of these modifications is not well evaluated in the existing literature. This study develops a bottom-up techno-economic assessment framework to determine the H 2 production costs in four alternative pathways: TiO 2 nanorods, fluorine-doped carbon nitride quantum dot-embedded TiO 2 (CNF: TNRs/TiO 2), g-C 3 N 4 , and g-C 3 N 4 /BiOI composite. Sensitivity and uncertainty analyses were also conducted to understand the impact of input parameters on the hydrogen production cost. The levelized costs of hydrogen (LCOH) are 4.9 - 0.70 + 0.75 , 5.7 - 0.65 + 0.45 , 5.8 - 1.15 + 0.55 , a n d 7.8 - 0.95 + 0.45 USD per kg of H 2 produced for TNRs, CNF: TNRs, g-C 3 N 4 -S, and BiOI/g-C 3 N 4 -S, respectively. In every pathway, the largest contribution is from capital investment and labour costs; together they make up around 75 % of the total cost. Material cost accounts for 13–29 % of the overall cost. The developed information can help in making investment decisions and policy formulation. [ABSTRACT FROM AUTHOR]

The energy sector is the largest contributor to gross domestic product (GDP), income, employment, and government revenue in both developing and developed nations. But the energy sector has a significant environmental footprint due to greenhouse gas (GHG) emissions. Efficient production, conversion, and use of energy resources are key factors for reducing the environmental footprint. Hence it is necessary to understand energy flows from both the supply and the demand sides. Most energy analyses focus on improving energy efficiency broadly without considering the aggregate energy flow. We developed Sankey diagrams that map energy flow for both the demand and supply sides for the province of Alberta, Canada. The diagrams will help policy/decision makers, researchers, and others to understand energy flow from reserves through to final energy end uses for primary and secondary fuels in the five main energy demand sectors in Alberta: residential, commercial, industrial, agricultural, and transportation. The Sankey diagrams created for this study show total energy consumption, useful energy, and energy intensities of various end-use devices. The Long-range Energy Alternatives Planning System (LEAP) model is used in this study. The model showed that Alberta’s total input energy in the five demand sectors was 189 PJ, 186 PJ, 828.5PJ, 398 PJ, and 50.83 PJ, respectively. On the supply side, the total energy input and output were found to be 644.84 PJ and 239 PJ, respectively. These results, along with the associated energy flows were depicted pictorially using Sankey diagrams. The Sankey diagrams reveal the current efficiencies within various end-use sectors and could help identify options for improving energy efficiency in order to reduce GHG emissions. [ABSTRACT FROM AUTHOR]

[Display omitted] • Novel method to estimate total technical potential for improving energy efficiency. • Bottom-up sector energy model used to characterize energy demands and opportunities. • Technology-explicit analysis framework used to estimate integrated energy savings. • Application to Canada's pulp & paper sector indicates major savings are possible. • Technical potential to reduce natural gas use by 95% and net electricity by 54% Industrial energy efficiency has long been recognized as a critical tool for energy management and emissions reduction and is increasingly considered to be an energy resource in its own right. However, the complexity of most industrial sectors creates barriers for modellers, companies, and policymakers in understanding and achieving the overall potential for efficiency-driven energy savings. To address this gap, we have developed a novel method that combines disaggregated bottom-up sector energy modelling with analysis of a comprehensive set of technology-explicit energy efficiency measures. This approach overcomes the deficiencies of top-down analyses and better represents the complexities of multi-measure efficiency investments compared to piecewise studies of individual measures. In this study, we demonstrated application of our method to the case of the Canadian pulp and paper sector. Our analysis shows that the sector can reduce its natural gas and electricity use by 95% and 41%, respectively, by adopting economical efficiency measures. This equates to 71 PJ of natural gas and 44 PJ of electricity saved annually and would result in cost savings of $81 per tonne of output sector-wide. Notably, we find that efficiency and fuel switching have the technical potential to reduce natural gas consumption by 98% across the sector. Taken together, the results provide quantitative evidence that energy efficiency is an underestimated resource for cost-effective energy savings in the Canadian pulp and paper sector. Our analysis framework can be applied to any industrial sector in any region to provide insights regarding energy conservation strategies and policy design. [ABSTRACT FROM AUTHOR]

• Six alternative or low-carbon fuels are evaluated for the cement sector. • Average long-term marginal abatement costs range from −70 to 138 CAD/tCO 2 e. • Up to 21% of emissions to 2050 can be eliminated with negative abatement costs. • Energy prices are the primary factor driving scenario cost performance. Limiting global warming and the pursuit of a net-zero global society by 2050 emphasizes the need to transform the hard-to-abate industrial sectors. The cement sector is the second-largest source of global industrial emissions, accounting for 8% of worldwide greenhouse gas emissions. Fuel switching in the cement sector is a decarbonization pathway that has not been explored in detail; previous studies involving fuel switching in the sector either view it from an energy efficiency lens or focus on a single technology. In this study, a framework is developed to evaluate and directly compare six fuel switching options (including hydrogen, biomass, municipal solid waste, and natural gas) from 2020 to 2050. Capital costs, non-energy operating costs, energy costs, and carbon costs are used to calculate marginal abatement costs and emulate cost based-market decisions. The developed framework is used to conduct a case study for Canada, using the LEAP-Canada model. This study shows that cumulative energy-related greenhouse gas emissions can be reduced by up to 21% between 2020 and 2050 with negative marginal abatement costs. Multiple fuel switching decarbonization pathways were established, reducing the likelihood that locality prevents meaningful emissions reduction and suggesting that, with low-carbon fuel and electricity policies, the sector can take significant steps towards emissions reduction. The developed framework can be applied to jurisdictions around the world for decision making, as nations move towards eliminating emissions from cement production. [ABSTRACT FROM AUTHOR]

• A novel energy-environmental model for penetration of oil sands cogeneration. • Interactions between industry cogeneration and provincial grid system considered. • 2% of oil sands greenhouse gas emissions could be mitigated by 2050. • The marginal abatement cost is $15 per tonne of carbon abated. • 92% of emission mitigation came from the steam-assisted gravity drainage sector. The purpose of this research is to evaluate greenhouse gas emission reduction opportunities from cogenerated electricity in oil sands production. A novel combined market penetration and bottom-up energy system modelling framework was developed to assess the long-range potential and marginal costs of cogenerated electricity in the oil sands. Feasible scenarios for incorporating cogeneration into the in situ, surface mining, and upgrading subsectors were developed along with four additional scenarios incorporating electricity-based technologies to improve in situ plant efficiencies. These scenarios were evaluated under three different carbon pricing policies; twenty-one scenarios in total covering the time period 2019 to 2050. The use of cogeneration in the oil sands for new production during this period was determined through market penetration modelling and the results were compared to a reference scenario of limited cogeneration growth. It was found that there is potential to provide 76 million tonnes of greenhouse gas abatement (2% of cumulative projected oil sands emissions) at a marginal cost of $15 per tonne of carbon abated compared to the reference scenario. The incorporation of electrical equipment, specifically well-pad boilers, well-pad compressors, additional steam compressors, and steam superheaters, resulted in additional costs that outweighed the benefits. A $50 per tonne of carbon dioxide equivalent carbon price (within the current Alberta emission reduction regulation) resulted in a 2% increase in forecasted greenhouse gas abatement potential and a $1.4/tonne of carbon dioxide equivalent decrease in marginal abatement costs compared to no carbon pricing. This research provides quantification of the greenhouse gas emission abatement potential and marginal abatement costs of cogeneration technologies to allow industry stakeholders and policymakers to compare these technology options to others when considering long-term greenhouse gas emission reduction. [ABSTRACT FROM AUTHOR]

• Fast pyrolysis, hydrothermal liquefaction, and intermediate pyrolysis processes were compared. • Novel Municipal Solid Waste (MSW) conversion process models were developed. • Centralized (C) and decentralized (D) systems for producing biocrudes from MSW were evaluated. • Transportation fuel (jet fuel, gasoline, diesel) production costs were calculated. The conversion of municipal solid waste (MSW) to transportation fuels can be an attractive route to reduce greenhouse gas emissions from the transportation and municipal sectors. Thermochemical conversion routes like hydrothermal liquefaction (HTL), fast pyrolysis (FP), and intermediate pyrolysis (IP) have been shown to be adept at converting organic dominant MSW into bio-crude or bio-oil. However, to produce compatible transportation grade fuels, it is necessary to upgrade the intermediate product (bio-crude or bio-oil) from all the processes, the extent of which differs depending on the process. Moreover, depending on the conversion technique, the production configuration can be either centralized or decentralized. In a centralized system, feed is transported to a facility to produce the intermediate and upgrade it (on-site upgrading), while in a decentralized system, the intermediate is produced elsewhere and transported to an upgrading facility (off-site upgrading).. Four scenarios were developed and modeled to compare the cost of production of gasoline, diesel and jet fuel from bio-crudes produced from HTL, FP, and IP.. The scenarios are: 1) a centralized HTL plant (C-HTL); 2000 dry t per day; on-site upgrading, 2) a centralized FP plant (C-FP); 2000 dry t per day; on-site upgrading, 3) a decentralized FP plant (D-FP); 50 dry t per day; off-site upgrading, and 4) a decentralized IP plant; 12 dry t per day; off-site upgrading.. Jet fuel was the primary fuel for comparison and the production costs were calculated to be $ 0.72, $ 0.85, $ 1.04, and $ 0.81 per liter for the C-HTL, the C-FP, the D-FP, and the D-IP plants, respectively. Secondary products (gasoline and diesel) can be produced alongside in cost ranges of $ 0.97 - $ 1.40 per liter and $ 1.02 - $ 1.47 per liter, respectively. The information conveyed in this study helps to identify the potential of thermochemical conversion processes to produce transportation fuels at competitive prices. The critical barriers to adopt such large-scale production processes and the opportunities of small-scale decentralized production are also mentioned. The outcomes of this study can be used to direct research and investment to address the major roadblocks that are slowing the extensive development of these technologies. [ABSTRACT FROM AUTHOR]

• Bottom-up life cycle assessment models were developed for battery storage systems. • Life cycle greenhouse gas (GHG) emissions of five battery storage systems were evaluated. • Four different stationary applications of batteries were examined. • The Li-ion has the highest net energy ratio (NER) and lowest GHGs in all applications. Electro-chemical batteries are widely used in portable devices and transportation, but they can also be used in the electricity grid for various applications. The assessment of the environmental impacts of electro-chemical storage systems for stationary use has received little attention. In this study, data-intensive, bottom-up life cycle assessment models were developed to assess the life cycle net energy ratios (NERs) and greenhouse gas (GHG) emissions of utility-scale stationary applications of five electro-chemical energy storage systems: sodium-sulfur, lithium-ion, valve-regulated lead-acid, nickel–cadmium, and vanadium redox flow. Four stationary application scenarios were considered: bulk energy storage, transmission and distribution (T&D) investment deferral, frequency regulation, and support of voltage regulation. The Li-ion storage system has the highest NER and lowest GHG emissions in every scenario. The life cycle GHG emissions range from 715 to 784 kg-CO 2 eq for sodium-sulfur, 625–659 kg-CO 2 eq for lithium-ion, 749–803 kg-CO 2 eq for valve-regulated lead-acid, 742–806 kg-CO 2 eq for nickel–cadmium, and 800–963 kg-CO 2 eq for vanadium redox flow per MWh of electricity delivered, depending on the application scenario. The results are highly influenced by the operation phase that involves charging the batteries. Lithium-ion and sodium-sulfur storage systems are the most suitable for all the application scenarios because of their longer cycle lives and higher energy densities. [ABSTRACT FROM AUTHOR]

• A zeolite-based heating system charged with air solar collectors was designed. • A techno-economic model of the zeolite 13X space heating system was developed to estimate the storage cost. • The levelized cost of energy storage is $0.06 per kWh over a 20-year lifespan. • The estimated capital cost scale factor of the zeolite-based space heating system is 0.761. • Sensitivity analysis suggests that zeolite pellet diameter is one of the key inputs affecting the design and the cost. Residential space heating contributes to greenhouse gas emissions because of natural gas combustion. One way to lower these emissions is to replace the natural gas space heating system with a zeolite 13X-based system. However, the economic feasibility of such a system is critical. There is limited information on the application and economic feasibility of a zeolite 13X-based heating system. In this study, we developed a data-intensive, bottom-up model to evaluate the life cycle cost of a zeolite 13X-based space heating system. We considered a traditional 16 kW space heating capacity for the zeolite-13X adsorbent and photovoltaic solar collector. The life cycle cost of the zeolite 13X-based system is 6 cents/kWh, a value comparable to traditional space heating systems like an electric boiler and natural gas-fired boilers. The uncertainty analysis shows that the system cost ranges from 5.4 cents to 6.1 cents/kWh. The overall cost is sensitive to the length-to-diameter ratio of the adsorbent vessel, zeolite pellet diameter, and solar collector potential. Improving these parameters would reduce the cost of the studied system. The scale factor for the capital cost of the zeolite 13X system was developed and it was estimated to be 0.76, which indicates that as the capacity of the system increases, the capital cost per unit output goes down. Overall, adsorbent storage connected to solar collectors for a space heating system is an economically competitive alternative technology to decarbonize the residential sector in cold climate regions. [ABSTRACT FROM AUTHOR]

• Techno-economic and life cycle assessments of energy storage systems were reviewed. • The levelized cost of electricity decreases with increase in storage duration. • Efficiency, lifetime, and duration of discharge influence the final costs and emissions. • A consistent system boundary is crucial for conducting life cycle assessment. • An integrated techno-economic and life cycle assessment model is recommended. Incorporating renewables in the power grid has challenges in terms of the stability, reliability, and acceptable operation of the power system network. One possible solution is to integrate an energy storage system with the power network to manage unpredictable loads. The implementation of an energy storage system depends on the site, the source of electrical energy, and its associated costs and the environmental impacts. Moreover, an up-to-date database with cost numbers, energy use, and resulting emissions is required for decision-making purposes. This paper reviews the techno-economic and environmental assessments of mechanical, electro-chemical, chemical, and thermal to give an update on recent developments and generate a relevant database for costs and emissions. We reviewed 91 publications, 58 on techno-economic assessment and 33 on life cycle assessment. We found that, because of economies of scale, the levelized cost of energy decreases with an increase in storage duration. In addition, performance parameters such as round-trip efficiency, cycle life, and cycle length highly influence the final costs and environmental footprints of various storage technologies. However, further research is required to build a bottom-up model that can handle all the technical parameters to quantify the levelized cost of energy and environmental footprints of the storage systems simultaneously. [ABSTRACT FROM AUTHOR]