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This study developed a novel assessment framework to analyze long-term energy transition in the road transport sector in which various technology options, market shares, policy measures, costs, and greenhouse gas emissions are considered in a single framework analysis. A data-intensive model was developed with the Low Emissions Analysis Platform (LEAP) and used to analyze policy scenarios up to 2050 for Alberta, Canada, a hydrocarbon-rich province with an emission-intensive energy sector. Three key policy measures – carbon pricing, zero-emission vehicle sales mandate, and incentivization – were analyzed in nine individual and combined policy scenarios. The transition to both hydrogen fuel cell electric vehicles and battery electric vehicles was assessed for all vehicle categories. Each fuel's full energy supply chain was modelled, including resource extraction, conversion, transmission and distribution, and fuelling, allowing for final and primary energy analysis. The findings show that carbon price and zero-emission vehicle incentives do not effectively lower greenhouse gas emissions on their own; zero-emission vehicle mandates are needed to transition the sector to a low-carbon energy system. The system-wide greenhouse gas emission footprints of hydrogen and battery electric vehicles are significantly below conventional vehicles in all cases. Scenarios biased towards battery electric vehicles had the most favorable results. The greenhouse gas emission footprint of hydrogen vehicles supplied by auto-thermal reforming with 91% carbon capture was lower than for battery electric vehicles powered by a primarily natural gas-based power grid. The findings on the effectiveness of carbon prices, incentives, and vehicle mandates should be considered by government policymakers aiming to reduce greenhouse gas emissions, infrastructure planners, and other energy stakeholders. [Display omitted] • Assessment of H 2 -FCEVs and BEVs for system-wide energy and emissions. • Impact of carbon price, ZEV sales mandate, and ZEV incentives analyzed up to 2050. • Evaluation of hydrogen production technologies including SMR and ATR with CCS. • Current policies result in 38% decline in system-wide emissions in 2050. • ZEV sales mandate is the most effective in reducing system-wide energy & emissions. [ABSTRACT FROM AUTHOR]

Waste-to-energy (WtE) is one of the municipal solid waste (MSW) management pathways that can reduce waste volumes while recovering energy. There has been considerable focus on using MSW for energy production; however, there are few integrated assessments of the optimal location and scale of the conversion of MSW to energy. This research develops a novel framework that integrates the analysis of candidate sites for MSW gasification facilities using a geographical information system (GIS) through a multi-criterion decision-making (MCDM) model with a mixed-integer linear programming (MILP) model to determine optimal scale and location. The most suitable candidate locations were identified through a GIS-based location-allocation analysis. A MILP model integrated with GIS was then used to determine the minimum per-unit electricity production costs by optimizing the numbers, locations, and sizes of the proposed WtE and preprocessing facilities. The key inputs to the optimization model are actual road and railway transportation distances, WtE gasification and preprocessing facility capital and installation costs, operation and maintenance costs, gate fee and tipping fees (the fee for disposal of ash at the landfill), and the municipal guidelines. The proposed integrated framework was applied in a case study for Alberta, a western province in Canada. The results indicate that at a 10% rate of return, electricity production is cost-competitive with current electricity prices. The per-unit cost of electricity production (COEP) was found to be only 16.14 $/MWh when the gate fee was treated as a revenue component. The optimal plant location was in Edmonton and the optimum plant size was 175 MW. Sensitivity and uncertainty analysis was conducted to understand the critical input parameters that impact the COEP. The results indicate that the COEP is most sensitive to changes in tipping fees, plant efficiency, capital cost, discount rate, and transportation cost. The developed framework is critical for investment decisions and policy development, and it can be applied globally with adjustments to data and assumptions. [Display omitted] • A novel integrated GIS-based optimization model is developed for MSW supply chain. • A GIS-based MCDM model is used to identify the candidate sites for WtE facilities. • ArcGIS network analysis is used to determine actual transportation distances. • The per unit COEP, 16.14 $/MWh, is competitive with the market price. • The proposed framework optimizes WtE facility numbers, locations, and sizes. [ABSTRACT FROM AUTHOR]

Research into the potential use of microalgae to produce biofuels is receiving significant attention. In the cold climates of countries like Canada, algae cultivation in open raceway pond (ORP) systems is limited to a short period of the year when pond surface water temperatures and ambient light conditions enable optimal culture growth. In this study we develop techno‐economic assessment models to predict, evaluate, and compare the techno‐economic results from three autotrophic algae cultivation scenarios to produce algae biomass. The first is a modeled ORP site located in the southern USA, which has a minimum biomass selling price (MBSP) for algae of $541 tonne−1 (T−1). The second scenario models an identical ORP system co‐located at a site near Fort Saskatchewan, a northern city in the province of Alberta, Canada. The resulting MBSP is $1288 T−1. A third scenario models a photobioreactor (PBR) cultivation system co‐located at the same northern Alberta site and shows algae production with an MBSP of $550 T−1. Each system is scaled to produce 2000 T day−1 ash‐free dry weight (AFDE) algae biomass. The study concludes that PBR systems deployed at this scale have the potential to reduce production costs significantly ($ T−1) compared to similarly sited ORP systems in Canada, despite climatic factors and high initial capital costs associated with PBR construction. Furthermore, the modeled PBR system required 0.3% of the water required by the ORP cultivation platforms (153 × 103 versus 59 527 × 103 m3) and 0.04% of the land (32 versus. 82 038 ha). © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd [ABSTRACT FROM AUTHOR]

Alberta's food processing industry is the second largest food waste producer after the household sector. Most of the waste currently produced from the food processing industry is landfilled. Decomposing landfill waste, moreover, emits greenhouse gases (GHG), which contribute to global warming. In this paper, we estimated the amount of food waste produced by Alberta's food processing industry by developing a geographical information system (GIS)-based model with data from food processing companies in the province. The companies were selected such that all sizes, types, and geographic locations were considered. The information was gathered on the amount and characteristics of food waste, the location of the processing facilities, and the food waste disposal method and then the total amount of food waste generated in Alberta was estimated. In addition, GIS maps were created to show the distribution of food waste throughout the province and the availability intensity. Finally, we estimated the potential energy that could be produced in the form of biogas and electricity using Alberta's food processing waste and mapped it as well. There is a potential to generate 852 GWh of electricity per year from Alberta's food processing waste, which is about 1% of the province's total electricity generation. This potential capacity could help in the development of waste-to-value-added facilities in Alberta. [ABSTRACT FROM AUTHOR]

• Life cycle assessment of utility-scale solar energy is performed. • Upstream production and assembly are the most emission-intensive life cycle stages. • Energy use during production and plant lifetime are the most sensitive parameters. • The system shows a net energy production with a net energy ratio up to 6.6. • The life cycle GHG emissions range from 98.3 to 149.3 g CO 2 eq /kWh. Grid-connected utility-scale solar PV has emerged as a potential pathway to ensure deep decarbonization of electricity in regions with fossil fuel-dominated energy mixes. Research on utility-scale solar PV projects mainly focuses on assessing technical or economic feasibility. Environmental performance assessments of large-scale solar applications are scarce. There is limited information on the greenhouse gas (GHG) emissions and energy footprints of utility-scale solar energy systems. Earlier studies conducted on small-scale solar systems have limited application in the grid system. We developed a comprehensive bottom-up life cycle assessment model to evaluate the life cycle GHG emissions and energy profiles of utility-scale solar photovoltaic (PV) system with lithium-ion battery storage to provide a consistent electricity supply to the grid with peak load options. We conducted a case study for a fossil fuel-based energy jurisdiction, Alberta (a western province in Canada). The results of the energy assessment show that raw material extraction, production, and assembly of solar panels are the key drivers, accounting for 53% of the total consumption. Energy consumed during battery manufacturing is responsible for 28%. The system shows a net energy production with a mean net energy ratio as high as 6.6 for two-axis sun tracking orientation. The life cycle GHG emissions range from 98.3 to 149.3 g CO 2 eq /kWh with a mean value of 123.8 g CO 2 eq /kWh. The largest emissions contribution is due to the manufacturing of batteries, 54% of the total emissions. The solar PV system offers a mean energy payback time of 3.8 years (with a range of 3.3 to 4.2 years). The results are highly sensitive to the expected lifetime of the system, the panel's peak wattage, and process energy consumption at various life cycle stages. [ABSTRACT FROM AUTHOR]

The depletion of fossil fuels as well as the greenhouse gas emissions from fossil fuel use have led to growing interest in biofuel production from biomass. A new technology, thermo-catalytic reforming (TCR), is one of the contributing interests. TCR technology integrates intermediate pyrolysis with a post-reforming stage to convert biomass into a high-quality bio-oil, biochar, and syngas. In this study, experiments were carried out using three Alberta-based biomass feedstocks – hardwood pellets, softwood pellets, and chips – in a 2 kg h−1 laboratory-scale TCR plant. The results show that the composition of the biomass has little effect on product yield and quality. The TCR gases had a higher heating value of 12.5–12.8 MJ kg−1 and a hydrogen content of 13–15 vol %. The produced TCR bio-oil had low water content (~5 wt %) and a heating value of 32–34 MJ kg−1. The high quality of the bio-oil is reflected in the low O/C ratio of 0.15 and TAN of 6–15 mg KOH g−1. The TCR biochar from all three feedstocks had a high heating value and a high carbon content, as well as low O/C and H/C ratios. A parametric study was conducted for the softwood pellets to observe the effect of reformer temperature (500–700 °C) and reactor temperature (400–550 °C). It was observed that at a reformer temperature of 700 °C, the gas yield increases at the expense of a reduction in bio-oil and biochar. The optimum reactor temperature for the TCR of softwood pellets was found to be 500 °C, in terms of both bio-oil quality and yield. • Thermo-catalytic reforming (TCR) technology incorporates intermediate pyrolysis with high temperature reforming. • The TCR bio-oil had low TAN (6–15 mg KOH/g), and high HHV (32–34 MJ kg−1). • The TCR gases had a hydrogen content of 13–15 vol % and HHV of 12–14 MJ kg−1. • Higher reforming temperature led to increase in gases at the expense of bio-oil. [ABSTRACT FROM AUTHOR]

Biomass can be converted to coal-like products known as hydrochar or biochar. Raw biomass generally has high moisture content. Wet torrefaction has gained considerable interest recently because of the unique characteristics of processing high-moisture content to a solid coal-like product. Five biomass feedstocks – wheat straw, pine, grape pomace, animal manure, and algae – were analyzed. The characteristics, as well as mass and energy yields of hydrochars and biochars from these feedstocks, were compared. Process simulation models were developed for both processes for each feedstock and techno-economic assessments conducted. The results indicate that hydrochars have superior characteristics, more coal-like properties, lower yields, and a higher cost of production (COP) than biochars for all cases except the pathways using manure as feedstock, where hydrochar COP is lower. The lowest production costs (without carbon credit) can be achieved through dry and wet torrefaction of grape pomace at 2.29 $/GJ and 4.14 $/GJ, respectively. Sensitivity and uncertainty analyses were also conducted for all pathways to understand the effects on production cost of varying different technical and economic factors. The results of this study will provide valuable insights into coal alternative products, especially in jurisdictions (like Alberta, Canada) planning to phase out coal plants. • Biocoal production via wet (WT) and dry (DT) torrefaction processes is investigated. • Five feedstocks (wheat straw, pine, grape pomace, manure, and algae) are studied. • Mass and energy yields and production costs (w and w/o carbon credit) are assessed. • Cost of biocoal production (COP) is competitive with coal price in some pathways. • Grape pomace has the lowest COP at 2.30 $/GJ and 4.15 $/GJ for DT and WT processes, respectively. [ABSTRACT FROM AUTHOR]

In this work, hydrothermal liquefaction (HTL) of corn stover, obtained from north Alberta farms, was performed at different temperatures of 250, 300, 350 and 375 °C, initial pressures (P i) of 300 and 600 psi and retention time (t r) of 0, 15, 30 and 60 min. All experiments were performed in a 250 mL autoclave reactor with 5 g corn stover and 30 mL de-ionized water (corresponding feed to water ratio of 1:6) in inert N 2 condition. The highest yield of heavy oil (29.25 wt%) was obtained at 300 °C, final pressure (P f) of 2200 psi and 0 min retention time. The highest yield of hydrochar (30.21 wt%) was obtained at 350 °C, P f of 3150 psi and t r of 15 min. Based on elemental analysis and energy calculation, highest carbon content and higher heating value for heavy oil was 76.32 wt% and 35.13 MJ/kg at 375 °C, P f of 600 psi and t r of 15 min; and for hydrochar it was 68.23 wt% and 24.7 MJ/kg at 350 °C, P f of 3150 psi and t r of 15 min. The GC–MS results for heavy oil indicated that majority of the compounds were phenolic in nature. SEM and FTIR results confirmed the presence of oxygen containing function groups on hydrochar surface. The gas was mainly composed of CO 2 , CH 4 , C 2 H 6 , C 2 H 4 , C 3 H 6 , C 4 H 8 , C 4 H 6 , C 5 H 12 , C 6 H 14 , and C 6 H 12. [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]

• The large-scale production pathway of high-performance perovskite solar cell modules is developed. • Scale factors were developed for each cost component of perovskite solar cells. • Perovskite solar panels for residential home application were designed. • The levelized cost of electricity is from 11.4 to 14.8 ¢/kWh. • The minimum sustainable price is $0.53-$0.9/W, comparable to commercial photovoltaic technologies. Perovskite solar cells (PSCs) have shown remarkable progress in recent years. Different materials and structures have been developed to improve the photoconversion efficiency and operational stability of PSCs. However, the economic and technical impacts of materials and design choice on the large-scale deployment are not well addressed in the literature. In this research, a pathway for producing titanium dioxide (TiO 2) nanorod-based perovskite solar modules was established and their manufacturing cost was estimated through the development of data-intensive, bottom-up techno-economic models. Material, utilities, and equipment requirements from available laboratory data to a mass production annual capacity of up to 21 MW were estimated through the development of scale factors. The minimum sustainable price and levelized cost of electricity were calculated. The direct manufacturing cost of the reference PSC module was estimated at $80.23/m2 and $0.73/W with a production capacity of 3.5 MWp. These costs decline to $47.15/m2 and $0.43/W at 21 MW production capacity. Material costs dominate the overall costs, fluorine-doped tin oxide glass being the most expensive material. The perovskite solar cell panels, when installed in residential homes in Alberta, Canada, were calculated to have a competitive levelized cost of electricity ranging from 7 to 17 cents per kWh. However, the cost was found to be extremely sensitive to the module efficiency, lifetime, and the solar insolation at the location of installation. [ABSTRACT FROM AUTHOR]

Process-level energy efficiency improvement is regarded as an effective technique for emissions reduction from the petroleum refining industry. Assessing the systems-level impacts of these energy efficiency improvements is crucial for effective long-term climate change policy- and decision-making. In this study, we developed a framework that integrates process simulation with integrated resource planning and techno-economic assessment techniques to evaluate long-term GHG mitigation potential in the refining sector. Detailed process simulations were done for eleven energy efficiency improvement measures in the refining sector. A case study was conducted for Alberta's (a province in western Canada) refining sector to assess GHG emissions reduction potential and their implications for long-term climate change policy-making. The GHG mitigation scenarios considered time horizons to the years 2030 and 2050. The results show that compared to the reference scenario, integrating the energy efficiency options in the refining sector will result in cumulative emissions reduction of 5%. About 60% of the anticipated emissions reductions are economically attractive. The proposed framework is an effective tool for the evaluation of long-term refining sector GHG mitigation potential and can be used for decision-making and policy formulation at various levels. • A framework is developed to assess GHG mitigation potential in the refining sector. • Process simulation, economic analysis, and energy planning models are integrated. • 22 mitigation scenarios are developed in time horizons ending in 2030 and 2050. • GHG mitigation potential is calculated and GHG abatement cost curves are developed. • 60% of the GHG emissions reductions are found to be economically attractive. [ABSTRACT FROM AUTHOR]