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Predatory publishing is the unethical and dishonest behavior of publishers who take advantage of researchers by charging them too much money and not providing good editing and peer-review services. Scholars, publishers and policymakers are seeking solutions to combat predatory publishing, which has become a major academic problem. This research paper provides a bibliometric analysis of the citation patterns and trends in the predatory publishing literature. The study analyzed the 100 top-cited papers on predatory publishing and provided insight into the types of documents, journals, authors, and countries that contributed to this field. The average citation per paper in the top 100 selected publications was 53.67. Open-access publications received a significantly higher average citation per paper than subscription-based papers. "Article" was the major type of document published, followed by "Notes," "Reviews" and "Editorials." Nature and Learned Publishing were the journals that contained the highest number of top-cited articles. J. Beall and D. Moher authored the highest number of papers, while A. Grudniewicz had the highest average citation per paper. USA and Canada were the top countries in these top-cited publications. This study will be beneficial to the all the stakeholders who may be interested in this area of research. [ABSTRACT FROM AUTHOR]

Abstract: Biomass is considered carbon neutral, and displacement of fossil fuel-based power by biomass-based power is one means to mitigate greenhouse gases. Large forest areas in British Columbia (BC), Canada, are infested by the mountain pine beetle (MPB). Dead wood from the infestation is expected to vastly exceed the ability of the pulp and lumber industry to utilize it; current estimates are that 200–600 millionm3 of wood will remain unharvested over the next 20 years. Regions where the damaged wood is not harvested will experience loss of jobs in the forestry sector, increased risk of forest fire hazard, carbon emissions from burned or decaying wood, and uncertainty about timing of replanting since this usually occurs at harvest. This paper reports the results of a detailed preliminary techno-economic analysis of producing power from MPB killed wood. Power plant size and location are critical factors affecting overall power cost. Overall cost of power rises steeply at sizes below 300MW net power output. By locating the power plant in an area of high infestation, transportation distances can be minimized. A 300MW power plant would consume 64millionm3 of wood over a 20-year lifetime, and hence is a significant sink for otherwise unharvestable wood. Cost estimates are based on harvesting of whole dead trees with roadside chipping and transport to a central power plant located in either the Nazko or Quesnel regions of BC. A circulating fluidized bed boiler with a conventional steam cycle is a currently available technology demonstrated at 240MW in Finland. The estimated power cost is $68 to $74 per MWh, which is competitive with other “green power” values in BC. Given recent values of export power in the Pacific Northwest, a 300MW MPB power plant is viable with a carbon credit below $15 per tons of CO2. [Copyright &y& Elsevier]

This study develops a framework for quantification of the available municipal solid waste (MSW), defines the geographical point source locations for the MSW feedstock, and determines optimal locations for potential waste‐to‐value‐added (W2VA) facility sites. The framework developed here is applied to Canada. To determine optimal sites for W2VA facilities, a three‐stage decision‐making model comprising exclusion analysis, preference analysis, and network analysis was developed. The fuzzy analytic hierarchy process (FAHP) and geographic information systems (GIS) were used in an integrated decision‐making network to prioritize the preference factors and facility locations; with these, a land suitability map (LSM) was developed and suitable candidate sites for W2VA facilities were obtained for Canada. The identified candidate sites were then used in a network analysis to select optimal sites with minimal travel distances. This study was used to determine 10 and 15 optimal sites for W2VA facilities in Western Canada and Eastern Canada, respectively. This study prioritized optimal sites based on the minimization of transportation distances. The highest priority site in Western Canada is Site 1, located in Lethbridge County, Alberta. It is connected with 74 TSs and can receive 2.42 million tonnes of MSW. The highest priority site in Eastern Canada is Site 11, which is located in West Nipissing, Ontario, and is connected with 42 transport stations (TSs) and can receive 1 million tonnes of MSW. The adaptability of the applied decision‐making model, competency of the developed LSM, and flexibility of the network analysis provide a competent supporting tool for authorities to identify optimal locations for W2VA facilities. [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]

The diversification of Canadian oil sands markets is imperative for the long-term economic growth of oil sands products. To ensure a competitive place in the global market, supply chain costs of oil sands must be as low as possible. This study conducts a comparative techno-economic analysis of potential pathways for the transportation of Canadian oil sands products (synthetic crude oil and diluted bitumen) to seaport destinations in the Asia-Pacific region. We developed data-intensive techno-economic models to estimate total supply chain costs from the production site in Alberta to ports in China, Japan, and India. Four pathways were developed using production (steam assisted gravity drainage), transportation (production-upgrader-port in Vancouver), upgrading, and shipping operations. A sensitivity analysis was conducted to identify cost ranges with their occurrence probability measures and evaluate the effect of key parameters for each stage of operation. Supply chain costs (C$ per barrel of bitumen) to China, Japan, and India are from 61–87, 60–86, and 62–90, respectively. Overall supply chain costs of dilbit (a blend of bitumen and diluent) and synthetic crude oil (SCO) are affected most by production and upgrading costs. The production and upgrading costs are influenced by capital cost, while pipeline lifetime and capacity highly impact transportation (pipeline) and shipping costs, respectively. The developed models can be used to predict total supply chain costs of different pathways in Canadian oil sand markets. [ABSTRACT FROM AUTHOR]

Greenhouse gas (GHG) emissions are currently at the crux of political, environmental, technological, and cultural discussions due to climate change. A drastic reduction of GHG emissions is needed in order to mitigate potentially catastrophic climate change impacts. Thus, thoroughly understanding emission sources is imperative. A disaggregated analysis of Canada’s future GHG emission projections has not yet been conducted. The objectives in this paper are to assess disaggregated GHG emissions in Canada for the years 2014, 2030, and 2050, and analyze the results through Sankey diagrams. Emissions are calculated using a bottom-up multi-regional accounting-based Long-range Energy Alternative Planning systems model. Each major economic sector in Canada is analyzed including the electricity generation, residential, commercial and institutional, industrial, transportation, and agriculture sectors. The emissions released in these sectors are traced to the resources and end-uses responsible. Results are presented for Canada and for provinces individually. GHG emissions contained in exported resources are evaluated. Results show that Canada’s business-as-usual GHG emissions will grow from 732 million tonnes in 2014 to 780 and 798 million tonnes in 2030 and 2050, respectively. Canada exports more emissions contained in resources than it emits. Per capita emissions intensity will fall by 14% between 2014 and 2050. Results are compared to climate targets and key areas of GHG mitigation potential are identified. Alberta’s oil and gas sector and Ontario’s transportation sector are the two single largest sectoral sources of emissions by 2050. This research can help policy makers, innovators, and the public better understand GHG emissions, which can lead to more effective GHG mitigation. [ABSTRACT FROM AUTHOR]

Electrolytic hydrogen produced from wind and solar energy is considered a long-term option for multi-sectoral decarbonization. The study objective is to develop a framework for assessing country-level hydrogen technical potential from wind and solar energy. We apply locational suitability and zonal statistical analyses methods in a geographic information system-based environment to derive granular insights on non-captive technically exploitable hydrogen potential in high-resource locations. Seven setback factors were considered for locational suitability, and integrated with modules developed for evaluating the wind and solar resource penetration from open-source theoretical renewable resource geospatial data and electricity-to-hydrogen conversion analyses. The technique applied in this study would be a relevant contribution to determining national and regional-wide electrolytic hydrogen production potentials in other jurisdictions with requisite adjustments to data and technical constraints. The results from the case study country, Canada – a major hydrogen-producing country – show that the technical hydrogen potentials from wind and solar energy are approximately 1,897 and 448 million metric tonnes per year, respectively, at least 6.3 times greater than global hydrogen demand in 2019. When we integrated locational data on enabling infrastructure, we discovered that the lack of access to power transmission lines in low-population-density areas of the country significantly reduces the exploitable wind- and solar-based hydrogen potential by over 80% and 6%, respectively. The findings of this study show that in the absence of spatial data on infrastructural constraints, the exploitable hydrogen potential in a jurisdiction can be overestimated, leading to improper guidance for policy and decision-makers. • A framework is developed to determine the H 2 technical potential from solar and wind. • The framework combines locational suitability and zonal statistical analysis in GIS. • A case study analysis was conducted for Canada. • Solar- and wind-based H 2 technical potential is 448 and 1898 Mt/year, respectively. • Low access to enabling infrastructure limits the exploitable potential by over 26%. [ABSTRACT FROM AUTHOR]

A comprehensive LCA (life cycle assessment) for transportation fuels (gasoline, diesel, and jet fuel) derived from Canada's oil sands was conducted, and all the current possible pathways from bitumen extraction to use in vehicles were explored. Authors, in earlier studies, have presented the energy consumption and GHG (greenhouse gas) emission results for individual unit operations-recovery, extraction, upgrading and refining. The LC (life cycle) inventory data for the current LCA study were obtained from theoretical model named FUNNEL-GHG-OS ( FUN damental E N gineering Principl E s- based Mode L for Estimation of G reen H ouse G ases in the O il S ands), developed from fundamental engineering principles. The impact of the cogeneration of electricity in oil sands recovery, extraction, and upgrading on the LC GHG emissions of gasoline was explored. LC WTW (well-to-wheel) GHG emissions range from 106.8 to 116 g-CO 2 equivalent/MJ of gasoline, 100.5 to 115.2 g-CO 2 equivalent/MJ of diesel, and 96.4 to 109.2 g-CO 2 equivalent/MJ of jet fuel, depending on the pathway. Combustion emissions (64.7%–70.3%) are the largest constituent of WTW emissions for gasoline production; recovery (through surface mining and steam assisted gravity drainage) forms 7.2%–16% depending on the LC production process of gasoline. [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]

[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]

A model-FUNNEL-GHG-OS ( FUN damental E N gineering Principl E s- based Mode L for Estimation of G reen H ouse G ases in the O il S ands) based on fundamental engineering principles was developed to estimate the specific energy consumption and GHGs (greenhouse gas emissions) for upgrading bitumen to produce SCO (synthetic crude oil). The model estimates quantity of SCO produced, the consumption of hydrogen, steam, natural gas and power in two different upgrading operations, namely delayed coking and hydroconversion. Hydroconversion upgrading is more energy and GHG (433.4 kgCO 2 eq/m 3 of bitumen) intensive than delayed coker upgrading (240.3 kgCO 2 eq/m 3 of bitumen) but obtains a higher yield of SCO. This research explores bitumen pathways in oil sands – upgrading bitumen to SCO, followed by transporting and refining SCO as compared to transporting and refining dilbit. The energy consumption, GHG emissions and volume of transportation fuels obtained from refining of different oil sands feeds has been investigated. Refining of oil sands products produce 7.9 to 15.72 gCO 2 eq per MJ of refined product. Refining of SCO to transportation fuels produces 41% and 49% less emissions than dilbit and bitumen respectively. [ABSTRACT FROM AUTHOR]

A model – FUNNEL-GHG-OS ( FUN damental E N gineering Principl E s-based Mode L for Estimation of G reen H ouse G ases in the O il S ands) was developed to estimate project-specific energy consumption and greenhouse gas emissions (GHGs) in major recovery and extraction processes in the oil sands, namely surface mining and in␣situ production. This model estimates consumption of diesel (4.4–7.1 MJ/GJ of bitumen), natural gas (52.7–86.4 MJ/GJ of bitumen) and electricity (1.8–2.1 kW h/GJ of bitumen) as fuels in surface mining. The model also estimates the consumption of natural gas (123–462.7 MJ/GJ of bitumen) and electricity (1.2–3.5 kW h/GJ of bitumen) in steam assisted gravity drainage (SAGD), based on fundamental engineering principles. Cogeneration in the oil sands, with excess electricity exported to Alberta’s grid, was also explored. Natural gas consumption forms a major portion of the total energy consumption in surface mining and SAGD and thus is a main contributor to GHG emissions. Emissions in surface mining and SAGD range from 4.4 to 7.4 gCO 2 eq/MJ of bitumen and 8.0 to 34.0 gCO 2 eq/MJ of bitumen, respectively, representing a wide range of variability in oil sands projects. Depending upon the cogeneration technology and the efficiency of the process, emissions in oil sands recovery and extraction can be reduced by 16–25% in surface mining and 33–48% in SAGD. Further, a sensitivity analysis was performed to determine the effects of key parameters on the GHG emissions in surface mining and SAGD. Temperature and the consumption of warm water in surface mining and the steam-to-oil ratio (SOR) in SAGD are major parameters affecting GHG emissions. The developed model can predict the energy consumption and emissions for surface mining and SAGD for oil sands. [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]

• Novel integrated assessment framework for electricity decarbonization. • Electricity generation greenhouse gases decrease 49% in the current policy scenario. • Electricity generation water consumption increases 22% in the current policy scenario. • Electricity decarbonization reduced the water consumption increase by 8% • The marginal abatement cost for decarbonization was found to be −$17.5/tonne. The generation of electricity can have major environmental impacts not only in terms of greenhouse gas (GHG) emissions but also in terms of water use. There has been limited integrated assessment of the environmental footprints of deep decarbonization of electricity generation. This research develops an integrated approach to evaluate the GHG emission mitigation, water footprints, and marginal abatement costs of electricity generation decarbonization pathways. The decarbonization of Canada's electricity sector was used as a case study. A Long-range Energy Alternative Planning model of the electricity generation sector was developed to determine future regional electricity generation technology mixes. A Water Evaluation and Planning model was also developed for the sector considering 530 power plants, 156 electricity generation water demand sites, and 74 major rivers. The energy and water-use models were integrated, and two scenarios were evaluated for a planning horizon of 2019–2050 using this integrated framework. The first scenario was based on current policy trajectories and the second was developed with a deep electricity decarbonization target of 100%. In the current policy scenario, water consumption and GHG emissions increased 22% and decreased 49%, respectively, by 2050 from 2019. The fully decarbonized scenario resulted in water consumption savings and negative marginal GHG abatement costs. The results quantify the co-benefits of decarbonizing electricity systems and show that transitioning toward renewables can reduce GHG emissions, water consumption, and system costs. These results may be important for policy development at the regional and national levels as well as internationally for jurisdictions looking to transition to carbon-free electricity. [ABSTRACT FROM AUTHOR]

The purpose of this research is to evaluate the greenhouse gas reduction potential and associated costs of integrating renewable energy technologies into Canada's oil sands. There is very limited analysis in the literature focused on the integration of renewable technology options in oil sands processes. This research addresses the gap by developing a novel framework that applies market penetration and bottom-up energy modeling techniques. A total of 27 long-term scenarios across oil sands extraction, upgrading, and electricity generation were investigated. The results show that up to 84 million tonnes of greenhouse gas emissions abatement (2.3% of oil sands GHG emissions) at a marginal greenhouse gas abatement cost of $1.3/tCO 2 e is available under a $30/tonne carbon incentive. Scenarios with no carbon incentive resulted in 69 million tonnes less greenhouse gas emissions abatement and a marginal greenhouse gas abatement cost increase of $36/tCO 2 e. Nuclear-based scenarios mitigated the largest amount of greenhouse gases and had the lowest marginal abatement costs. Geothermal energy, bioenergy, and hydropower were cost effective in certain scenarios but had limited greenhouse gas emission reduction potential. Wind and solar technologies failed to displace existing processes in the scenarios considered. The results from this study may be of value to government policy makers and industry representatives aiming to reduce greenhouse gases. • A novel framework applying market penetration and bottom-up energy modeling. • Renewable and low-carbon energy supply options for the Canadian oil sands industry. • Up to 3.7% of GHG emissions between 2019 and 2050 could be mitigated at -$6/tCO 2 e. • Nuclear energy technologies provided most of the GHG emission abatement potential. • Removing a $50 per tonne carbon price reduced GHG abatement by 89%. [ABSTRACT FROM AUTHOR]

Carbon capture, utilization, and storage (CCUS) has been identified as the only option for substantially reducing greenhouse gas (GHG) emissions from fossil fuel-based processes. There has been limited research into the long-term GHG reduction potential of integrating CCUS into unconventional oil extraction processes. We developed a CCUS-oil sands market penetration model and integrated it with a bottom-up energy model (LEAP-Canada) to conduct a cost-benefit case study for the Canadian oil sands. Scenarios were developed considering currently available CCUS technologies and were investigated under different carbon pricing policies. Cumulative GHG emission mitigation potential from the CCUS applications ranged from 3 to 232 million tonnes (Mt) with marginal costs of $-28–42/tCO 2 e. Carbon pricing led to an average 3% increase in 2050 market shares of the technologies, resulting in additional GHG abatement of 4.9% (172 Mt). CCUS was found to be the costliest GHG emission mitigation option compared to increased integration of cogeneration and energy efficiency measures. The maximum cumulative oil sands GHG emission mitigation achieved in this study was 7%. This research ultimately provides insights into applications of CCUS technologies into the oil sands industry that might be useful to industry planners and policymakers and support the sustainable development of oil sands resources. • A novel bottom-up energy modeling framework for carbon capture in the oil sands. • 7% of industry GHG emissions from 2020 to 2050 could be mitigated at -$16.15/tCO 2 e. • Oxyfuel boilers powered by bituminous fuels provide 90% of mitigation potential. • Carbon pricing policies increased GHG abatement potential by 66 Mt. • Opportunities to utilize captured carbon increased GHG abatement potential by 94 Mt. [ABSTRACT FROM AUTHOR]

The global demand of steel production is growing, and so are the carbon dioxide emissions from the sector. Research has confirmed that 15 to 20% further energy efficiency improvement is possible, which would reduce the sector's greenhouse gas emissions and help meet global emission reduction initiatives. In this context, this research aims at developing a bottom-up system-based model to evaluate the long-term potential of energy efficiency alternatives in greenhouse gas mitigation. A case study was conducted for the Canadian iron and steel sector. The developed framework involves review of the state of the art in iron and steel production technologies, demand tree development, energy-environmental modeling, scenario development, and analysis. Twenty-six mitigation scenarios were developed in planning horizons ending in 2030 and 2050. A 13% improvement in Canadian iron and steel energy efficiency could be achieved by increasing the production share of the electric arc furnace route from 41% in the base year to 56% by 2050. The results of the analysis suggest that 19 and 38 million tonnes of greenhouse gas emission reduction are achievable in the 2010–2030 and 2010–2050 planning horizons, respectively. This translates to an approximately 6% reduction in emissions compared to the baseline scenarios at a cost of − $76 and − $51 per tonne of carbon dioxide equivalent in the 2010–2030 and 2010–2050 time periods, respectively. The results also reveal that more than 85% of the potential emission reductions are achievable with negative costs and are economically attractive. The study provides insights to decision makers at different levels of industry and government. [ABSTRACT FROM AUTHOR]

The industrial sector, accounting for 30% of global greenhouse gas (GHG) emissions, is among the key drivers of human-induced climate change impacts. Given this volume of emissions, the sector could play a critical role in mitigating climate change. Canada is among the top 10 global GHG emitters and its industrial sector is responsible for more than 39% of national emissions. GHG emissions from the sector increased by almost 32% between 1990 and 2017 and are expected to almost double by 2050 if no measures are taken. This paper aims to evaluate how different technical and economic factors have contributed to the increasing GHG emission trends in Canada's industrial sector between 1990 and 2014. The Logarithmic Mean Divisia Index was developed and implemented as the decomposition method. Results from the analysis suggest that activity level is the biggest contributor to the increase in industrial GHG emissions between 1990 and 2014, which ranged from 5 Mt CO 2 eq in 1994 to 57 Mt CO 2 eq in 2014 compared to the 1990 baseline. Increased shares of low carbon-intensive industries and fuel switching contribute to GHG emission mitigation from the sector. The structural change is responsible for GHG reductions of 1.1 and 23.4 Mt CO 2 eq in 2000 and 2014, respectively. The impacts from fuel mixs and increased shares of low-carbon fuel ranged from −1 Mt CO 2 eq in 1994 to 16 Mt CO 2 eq in 2011. Despite improvements in process-energy-intensity (i.e., the energy consumed per unit of product) in several industries, changes in economic energy intensity (energy consumed per unit of economic output) have resulted in increased GHG emissions. These changes are mainly driven by changes in the process-energy intensity of the oil sands mining sector, the largest contributor to industrial GHG emissions in Canada. Image 107490 • Historical GHG emissions trends from Canada's industrial sector were analyzed. • GHG emissions decomposition analysis was done for the years 1990–2014. • The impacts of driving factors on increasing GHG emission trends were examined. • Activity level was found to be the main driver of GHG emissions. • Fuel switching and electricity decarbonization mitigate industrial GHGs. [ABSTRACT FROM AUTHOR]

The objective of this study is to investigate greenhouse gas mitigation pathways for the iron, gold, and potash mining sectors in Canada. These sectors have not widely accepted the available cleaner production strategies and so there is potential to reduce greenhouse gas emissions. It is important to fully realize this potential as soon as possible to support efforts to limit global warming. We conducted cost-benefit analyses of implementable greenhouse gas reduction strategies in order to inform policy and industry. Twenty-four greenhouse gas emission reduction options not yet implemented in Canada were identified following a review of current processes and operations at 102 mine sites. We developed a novel model to assess these options, integrating technology diffusion rates and long-term energy-environmental modelling. We found that the maximum greenhouse gas reduction potential can be realized through simultaneously implementing fifteen technology changes, eliminating 21 million tonnes of CO 2 eq. by 2050. Furthermore, we showed that the marginal greenhouse gas abatement costs are negative, indicating that the industry would also achieve long-term cost savings if these changes were pursued. Implementing high pressure grinding rolls in iron mining and electric and diesel hybrid haul trucks in underground gold mining and potash mining have the most favorable greenhouse gas abatement costs of −4120, −3096, −701 $/tonne, respectively. These results show that these technology changes should be pursued since both environmental benefit and cost savings would be achieved. Image 1 • A bottom-up energy model was developed for iron, gold, and potash mining sectors. • Twenty-four GHG mitigation options were identified and assessed. • Energy consumption reduction potential is 9% through 2020–2050 across the sectors. • 10% and 20% of GHG emissions could be reduced in iron and gold mining, respectively. • More than 95% of the GHG emission reductions have negative marginal abatement costs. [ABSTRACT FROM AUTHOR]

Carbon capture and utilization (CCU) and carbon dioxide removal (CDR) technologies have the potential to significantly contribute to GHG reduction. Numerous studies have evaluated the CO 2 reduction effects and economics of CCUs and CDRs; however, uncertainties in these evaluations due to various regional characterizations and future technological transitions are of high importance. In this study, four synthetic fuels (fuels produced from captured CO 2 and H 2), methanol, methane, gasoline, and diesel, were evaluated by life cycle assessment (LCA) and techno-economic assessment (TEA). Five representative countries with different regional characteristics were selected for the study. A bottom-up integrated LCA/TEA approach was used, involving detailed process simulations to avoid uncertainties and to evaluate future technological transitions based on direct air capture (DAC) and renewable energy. The overarching objective of this study was to provide a transparent framework with a common dataset generation methodology to determine the countries that have the advantages/disadvantages in synthetic fuel production and sale, considering the local operational parameters and large-scale introduction of DAC/renewable energy. Such multiple synthetic fuel analyses across various jurisdictions have not been conducted in previous studies. The results showed that the highest and lowest CO 2 reductions were achieved by diesel (average 6.33 kg-CO 2 ·kg−1) and methanol (average 3.43 kg-CO 2 ·kg−1), respectively, whereas the highest and lowest product costs were of gasoline (average 2.96 USD·kg−1) and methanol (average 0.82 USD·kg−1), respectively. The technological transition using DAC and renewable energy showed average CO 2 emission reductions of 47% (methanol), 99% (methane), 545% (gasoline), and 621% (diesel). Moreover, in the future, the lowest CO 2 emission reduction costs are expected in Germany for methanol and diesel, Australia for methane, and Canada for gasoline. These findings can contribute to improving international collaboration to promote CCU and CDR technologies. • Carbon capture and utilization (CCU) and CO 2 removal (CDR) technologies were evaluated for four representative synthetic fuels. • CO 2 reductions and costs were analyzed for different CCU pathways, scenarios, and countries. • Diesel fuel was found to be the most effective CCU pathway in terms of cost and potential. • Germany and Canada have economical advantage for CCU production, while U.S, has in potential. • Detailed process modeling was combined with cost and GHG emission estimation for multiple jurisdictions. [ABSTRACT FROM AUTHOR]

The growth in bitumen and synthetic crude oil (SCO) production in the Canadian oil sands industry has superseded pipeline capacity growth in recent years, leading to the increased interest in the transport of crude oil by rail to desired markets. However, the specific techno-economic parameters that facilitate increased competitiveness of either transportation mode against the other is seldom addressed in the existing literature. This paper involves the development of a rail and pipeline techno-economic transport model, which is used to ascertain the transportation cost of both options for a market distance range of 1–3000 km and a production scale of 100,000–750,000 barrels per day (bpd). The transportation cost for either option is highly sensitive to the market distance, transportation scale and crude grade being transported; however, pipelines are generally more competitive for large transportation scales, while the cost-effectiveness of rail transport is realized particularly at smaller transportation scales. In general, pipelines are cost efficient for the transportation of crude oil in the majority of scenarios investigated. Rail can be more economical than pipeline under certain conditions. The use of insulated rail cars for the transport of raw bitumen is the area with greatest potential for cost competitiveness against pipelines. [ABSTRACT FROM AUTHOR]

Electric vehicle charging by renewable energy can help reduce greenhouse gas emissions. This paper presents a data-intensive techno-economic model to estimate the cost of charging an electric vehicle with a battery capacity of 16 kW h for an average travel distance of 65 km from small-scale renewable electricity in various jurisdictions in Canada. Six scenarios were developed that encompass scale of operation, charging time, and type of renewable energy system. The costs of charging an electric vehicle from an off-grid wind energy system at a charging time of 8 h is 56.8–58.5 cents/km in Montreal, Quebec, and 58.5–60.0 cents/km in Ottawa, Ontario. However, on integration with a small-scale hydro, the charging costs are 9.4–11.2 cents/km in Montreal, 9.5–11.1 cents/km in Ottawa and 10.2–12.2 cents/km in Vancouver, British Columbia. The results show that electric vehicle charging from small-scale hydro energy integration is cost competitive compared charging from conventional grid electricity in all the chosen jurisdictions. Furthermore, when the electric vehicle charging time decreases from 8 to 4 h, the cost of charging increases by 83% and 11% from wind and hydro energy systems, respectively. [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]

The main objective of this study is to assess energy-use reduction strategies in extraction and upgrading of oil sands for greenhouse gas mitigation in Canada's oil sands sector. A bottom-up integrated resource-planning model for oil sands extraction and upgrading processes was developed. The model is a novel application of an energy accounting-based framework and accurately simulates energy demand and supply in the oil sands from 2007 to 2050. Thirty energy-use reduction scenarios were evaluated covering in situ extraction, surface mining, and bitumen upgrading processes. The energy savings, greenhouse gas emission mitigation, and costs associated with each scenario were determined with the model. Implementing in situ energy-use reduction measures resulted in the highest single measure greenhouse gas mitigation potential of 86 million tonnes CO 2 e at a marginal greenhouse gas abatement cost of -$91/tonne of CO 2 e by 2050. For the scenarios in surface mining and bitumen upgrading, the highest single measure greenhouse gas mitigation potentials are 17 and 16 million tonnes CO 2 e by 2050 at marginal greenhouse gas abatement costs of -$65/tonne of CO 2 e and -$21/tonne of CO 2 e, respectively. All strategies result in a negative $/tonne of CO 2 e cost, indicating a net benefit for investing in the strategies. If the strategies are implemented together, there is an ultimate potential to reduce sector-wide cumulative energy consumption and greenhouse gas emissions in the oil sands by 8% and 7%, respectively, by 2050. Decision-makers at company or government levels can use these results to support both environmental and cost-saving initiatives. Image 1 • A bottom-up energy supply-demand model for the oil sands sector was developed. • Sector-wide energy consumption could be reduced up to 8%. • An annual average of 7.6 million tonnes of GHG emissions could be mitigated. • 65% of evaluated GHG mitigation potential is from in situ extraction. • All GHG emission mitigation strategies have negative marginal abatement costs. [ABSTRACT FROM AUTHOR]