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The lack of fresh water, especially for the land-locked & arid regions, is becoming a significant barrier to the sustainable development of humanity. This has generated an urgent need to explore the solar-driven atmospheric water generation (S-AWG) technologies with high water yield. This research experimentally compares the performance of silica gel and molecular sieve on a novel S-AWG system. 25 kg of each desiccant material is used in a packed desiccant bed structure. In the nocturnal phase, adsorption is performed followed by regeneration during the day using hot air generated from evacuated tube solar air heater (ET-SAH). An air-to-air heat exchanger is employed for condensing the water vapors released in the process air after the desiccant bed regeneration. The water generated from silica gel is 1790 ml with energy & exergy efficiency of 23.14% & 10.43%, respectively. From the molecular sieve, 350 ml of water is generated with energy & exergy efficiency of 21.74% & 9.58%, respectively. The economic analysis of the system reveals that the cost of water generated from silica gel is 0.21 $/L, while from molecular sieve is 1.21 $/L. Water testing reports of the produced water using both the desiccant materials infers that it is drinkable. [Display omitted] • Solar atmospheric water generation (S-AWG) based on air-to-air heat exchanger. • Comparison of S-AWG system by using silica gel & molecular sieve. • 1790 ml/day water is produced from silica gel & 350 ml/day from molecular sieve. • Energy & exergy efficiency of the S-AWG system is 23.14% & 10.43%, respectively. • Water generated from silica gel costs 0.21 $/L. [ABSTRACT FROM AUTHOR]

Fluctuations in conventional crude oil price globally and initiatives towards the phase-out of coal-based power have initiated a focus on alternative sources of liquid fuels from natural gas and coal. Gas-to-liquid (GTL) and coal-to-liquid (CTL) processes are two liquefaction technologies that could be used. There is a limited work on either the development of scale factors to estimate capital costs or on techno-economic assessments of the plants. This study addresses this gap and focusses on western Canada, which has large deposits of coal and natural gas. The capital costs of the plants' key equipment are estimated through the development of cost scale-up factors. The production cost for 50,000 bbl/day of liquid fuels from GTL and CTL plants is estimated through modelling using a bottom-up approach. The developed scale-up factors for the GTL and CTL plants were found to be 0.70 and 0.65, respectively. For both plants, most of the benefits of economies of scale are achieved at a capacity of 20,000 bbl/day. The production costs of the GTL and CTL processes are 44.61 and 57.65 Canadian cents/liter respectively. With carbon capture and sequestration (CCS), the production cost of fuel from the CTL plant is higher than from the GTL plant. [ABSTRACT FROM AUTHOR]

There is considerable focus on oil sands transportation fuel production. However, most studies focus on greenhouse gas emissions; there is limited work on understanding the life cycle water footprint. This study is an effort to address this gap. The main objective of this study is to develop water demand coefficients of the complete life cycle of oil sands transportation fuel production. Water demand coefficients include consumption and withdrawals, which were estimated for different oil sands unit operations pathways for production in Alberta, Canada. The pathways include three key operations, bitumen extraction, upgrading, and refining. The water consumption coefficients for the complete life cycle range from 2.08 to 4.19 barrels of water (bbl W ) per barrel of refined oil (bbl BUR ) and 2.87–5.16 bbl W /bbl BUR for water withdrawals coefficients. The lower limit for water demand coefficients is found in refined and upgraded in situ steam assisted gravity drainage recovery and the higher amount in refined and upgraded surface mining recovery. A sensitivity analysis was conducted through Monte Carlo simulations to study the uncertainty of the water demand coefficients. The water consumption coefficient for oil sands extraction at a 90% probability was found to be 0.34–2.8 bbl W /bbl B, upgrading be 0.87 bbl W /bbl U , and refining to be 1.52 bbl W /bbl R . [ABSTRACT FROM AUTHOR]

Despite improvements, the residential sector is one of most energy-intensive sectors in the world and is the third largest consumer of energy across Canada, and in Alberta in particular. This study investigates opportunities to improve energy efficiency and reduce greenhouse gas emissions (GHG) in the residential sector. A case study for Alberta is conducted. Energy modeling and scenario analyses are used to project future energy savings and greenhouse gas mitigation potential in the residential sector. Seventeen energy-saving options are identified in different residential subsectors, including space heating and cooling, water heating, appliances, and lighting. The long-term impacts (i.e., from 2013 to 2050) of these technologies in terms of energy savings and greenhouse gas mitigation potential are assessed using the Long-range Energy Alternative Planning model. For the evaluated options, more than 80% of GHG mitigation is achievable with negative GHG abatement cost. A GHG abatement cost curve is developed to assess the economic performance of various options. The results of the cost curve indicate that efficient lighting, efficient furnaces, and high efficiency appliances are the three areas in which the most GHG mitigation can be achieved at the lowest cost. The results provide invaluable insights to policy makers. [ABSTRACT FROM AUTHOR]

The demand for hydrogen in conventional and unconventional oil refining industries is considerable. Currently, the predominant source of hydrogen is from fossil fuel production pathways, in particular, steam methane reforming (SMR), which incurs a significant greenhouse gas (GHG) emissions footprint. Thus, alternative environmentally benign sources of hydrogen will be needed in oil refinery complexes the world over, if their greenhouse gas (GHG) emissions footprint is to be reduced materially. In this paper, an integrated data-intensive techno-economic model is developed to provide a credible estimate of hydropower-hydrogen production costs in Western Canada. The minimum hydrogen production cost for the hydropower-hydrogen plant amounts to $2.43/kg H 2 – this corresponds to an electrolyser farm with 90 units of a 3496 kW (760 Nm 3 /h) rated electrolyser. This cost is competitive with SMR/SMR coupled with carbon capture and sequestration (CCS) production costs, which vary from $1.87/kg H 2 to $2.60/kg H 2 . This point is buttressed by the fact that if existing hydropower plants are used (hence negating hydropower capital costs), the minimum production cost amounts to $1.18/kg H 2 . Hydrogen from hydro power, under the techno-economic conditions considered here, is competitive compared to SMR. [ABSTRACT FROM AUTHOR]

Abstract: This study estimated the greenhouse gas emissions (GHGs) and net energy ratio (NER) for producing hydrogenation-derived renewable diesel (HDRD) from canola and camelina in Western Canada. Using 1 MJ of energy in the HDRD produced as the functional unit, a variety of scenarios were evaluated to account for variations in allocation methods, co-products, oilseed yield, N2O emission factor, and land use change (LUC). In producing HDRD, the farming stage and the oil conversion stage (i.e. the HDRD production stage) are the most energy and emission intensive. For canola based HDRD, the GHGs and NERs lie in the ranges of 33–94 gCO2e/MJ and 1.2–2.2 MJ/MJ respectively. For camelina based HDRD, the GHGs and NERs range from 30 – 82 gCO2e/MJ and 1.0–2.3 MJ/MJ respectively. In the base scenario (mass allocation; oilseed meal and propane fuel gas co-products; average yield; 0.76% N2O emission factor; LUC ignored), HDRD from camelina (38 gCO2e/MJ, 2.0 MJ/MJ) is environmentally superior to HDRD from canola (48 gCO2e/MJ, 1.7 MJ/MJ) due to lower agricultural inputs and higher yield for camelina. Considering all of the scenarios examined, HDRD from both crops appears to be more sustainable than fossil diesel. [Copyright &y& Elsevier]

Abstract: Hydrogen is produced via steam methane reforming (SMR) for bitumen upgrading which results in significant greenhouse gas (GHG) emissions. Wind energy based hydrogen can reduce the GHG footprint of the bitumen upgrading industry. This paper is aimed at developing a detailed data-intensive techno-economic model for assessment of hydrogen production from wind energy via the electrolysis of water. The proposed wind/hydrogen plant is based on an expansion of an existing wind farm with unit wind turbine size of 1.8 MW and with a dual functionality of hydrogen production and electricity generation. An electrolyser size of 240 kW (50 Nm3 H2/h) and 360 kW (90 Nm3 H2/h) proved to be the optimal sizes for constant and variable flow rate electrolysers, respectively. The electrolyser sizes aforementioned yielded a minimum hydrogen production price at base case conditions of $10.15/kg H2 and $7.55/kg H2. The inclusion of a Feed-in-Tariff (FIT) of $0.13/kWh renders the production price of hydrogen equal to SMR i.e. $0.96/kg H2, with an internal rate of return (IRR) of 24%. The minimum hydrogen delivery cost was $4.96/kg H2 at base case conditions. The life cycle CO2 emissions is 6.35 kg CO2/kg H2 including hydrogen delivery to the upgrader via compressed gas trucks. [Copyright &y& Elsevier]

Abstract: Biomass can be used for the production of fuels, and chemicals with reduced life cycle (greenhouse gas) emissions. Currently, these fuels and chemicals are produced mainly from natural gas and other fossil fuels. In Western Canada, forest residue biomass is gasified for the production of syngas which is further synthesized to produce different fuels and chemicals. Two types of gasifiers: the atmospheric pressure gasifier (commercially known as SilvaGas) and the pressurized gasifier (commercially known as RENUGAS) are considered for syngas production. The production costs of methanol, (dimethyl ether), (Fischer-Tropsch) fuels, and ammonia are $0.29/kg, $0.47/kg, $0.97/kg, and $2.09/kg, respectively, for a SilvaGas-based gasification plant with a capacity of 2000 dry tonnes/day. The cost of producing methanol, DME, F-T fuels, and ammonia in a RENUGAS-based plant are $0.45/kg, $0.69/kg, $1.53/kg, and $2.72/kg, respectively, for a plant capacity of 2000 dry tonnes/day. The minimum cost of producing methanol, DME, F-T fuels, and ammonia are $0.28/kg, $0.44/kg, $0.94/kg, and $2.06/kg at plant capacities of 3000, 3500, 4000, and 3000 dry tonnes/day, respectively, using the SilvaGas-based gasification process. Biomass-based fuels and chemicals are expensive compared to fuels and chemicals derived from fossil fuels, and carbon credits can help them become competitive. [Copyright &y& Elsevier]

Abstract: The environmental performance of production and distribution of densified form of lignocellulosic biomass (i.e., agri-residue based pellets) in Western Canada in terms of energy and greenhouse gas (GHG) emission was assessed. The results show that energy usage and resulted emissions are highest in field activities especially if emission and energy are attributed to straw in farming stage where nitrogen fertilizer is the highest contributor. Significant reduction of energy use (64%) and emission (65%) are possible if the organic fertilizer is used in farming. Adopting the zero tillage option instead of conventional practice results in energy saving (10%) and emission reduction (8%). From the scenario analyses it is also evident that using biomass as an energy source during drying or no drying in pellet production stage or using alternate mode (i.e., truck and train) of transport for pellet delivery result in less than 5% reduction of the energy use and emissions compared to the base case. Agri-pellet has the potential to offset substantial amount of GHG emission compared to other fuel sources including wood pellets. The energy and emission of production chain of agri-pellets may vary between countries but overall trend compared to other fuel sources would be similar. [Copyright &y& Elsevier]

Abstract: In this study, forest residues (limbs, tops, and branches) and straw (from wheat and barley) are considered for producing biohydrogen in Western Canada for upgrading of bitumen from oil sands. Two types of gasifiers, namely, the Battelle Columbus Laboratory (BCL) gasifier and the Gas Technology Institute (GTI) gasifier are considered for biohydrogen production. Production costs of biohydrogen from forest and agricultural residues from a BCL gasification plant with a capacity of 2000dry tonnes/day are $1.17 and $1.29/kg of H2, respectively. For large-scale biohydrogen plant, GTI gasification is the optimum technology. The delivered-biohydrogen costs are $2.19 and $2.31/kg of H2 at a plant capacity of 2000dry tonnes/day from forest and agricultural residues, respectively. Optimum capacity for biohydrogen plant is 3000dry tonnes/day for both residues in a BCL gasifier. In a GTI gasifier, although the theoretical optimum sizes are higher than 3000dry tonnes/day for both feedstocks, the cost of production of biohydrogen is flat above a plant size of 3000dry tonnes/day. Hence, a plant at the size of 3000dry tonnes/day could be built to minimize risk. Carbon credits of $119 and $124/tonne of CO2 equivalent are required for biohydrogen from forest and agricultural residues, respectively. [Copyright &y& Elsevier]

The greenhouse gas (GHG) mitigation potentials of number of selected Biomass Energy Technologies (BETs) have been assessed in Vietnam. These include Biomass Integrated Gasification Combined Cycle (BIGCC) based on wood and bagasse, direct combustion plants based on wood, co-firing power plants and Stirling engine based on wood and cooking stoves. Using the Long-range Energy Alternative Planning (LEAP) model, different scenarios were considered, namely the base case with no mitigation options, replacement of kerosene and liquefied petroleum gas (LPG) by biogas stove, substitution of gasoline by ethanol in transport sector, replacement of coal by wood as fuel in industrial boilers, electricity generation with biomass energy technologies and an integrated scenario including all the options together. Substitution of coal stoves by biogas stove has positive abatement cost, as the cost of wood in Vietnam is higher than coal. Replacement of kerosene and LPG cookstoves by biomass stove also has a positive abatement cost. Replacement of gasoline by ethanol can be realized after a few years, as at present the cost of ethanol is more than the cost of gasoline. The replacement of coal by biomass in industrial boiler is also not an attractive option as wood is more expensive than coal in Vietnam. The substitution of fossil fuel fired plants by packages of BETs has a negative abatement cost. This option, if implemented, would result in mitigation of 10.83 million tonnes (Mt) of CO2 in 2010. [Copyright &y& Elsevier]

The industrial sector accounts for more than one-third of global energy consumption and greenhouse gas (GHG) emissions. In the sector, the chemical industry makes up nearly 30% of global industrial energy consumption. In this study, a framework is developed to apply bottom-up energy modelling for analyzing energy efficiency improvement and GHG mitigation potential in the chemical sector. Also, techno-economic and policy analyses are used to analyze the applicability and economic performance of different mid- to long-term energy efficiency measures. The comprehensive, data-intensive, and technology-rich model is flexible and can be used to study the GHG mitigation potential in different regions. A case study was conducted for Alberta, one of the biggest industrial hubs in Canada, using the Long-range Energy Alternative Planning model. Twenty-eight GHG mitigation scenarios in the petrochemical and fertilizer industries (the two major chemical industry sub-sectors) were developed. The costs of implementing each mitigation measure were calculated and used to develop cost curves. The results suggest that cumulative mitigation potential from the chemical industry would be 7.1 and 29.7 megatonnes CO 2 equivalent in the periods ending 2030 and 2050, respectively. We also found that more than 75% of the emissions reductions are achievable with negative cost. [ABSTRACT FROM AUTHOR]

The economic feasibility of producing ammonia through the gasification of three different feedstocks produced in pulp and paper mills is investigated in this paper. The first case uses black liquor, the main by-product of the kraft pulping process, as the feedstock, and in the other two cases pulp sludge (PS) and waste sludge (WS) are co-gasified with black liquor. For all three cases, a process model in which mass and energy balances were calculated was developed. The model results were used to estimate the equipment size and estimate costs. Techno-economic models were developed and ammonia production costs were calculated. A case study for Alberta, a western Canadian province, was conducted. The results indicated that for a 10% discount rate (or internal rate of return [IRR]), ammonia production in all three cases is cost competitive with current ammonia prices. The cost of production (COP) of ammonia for all three cases ranges from 743 to 748 $/t. Sensitivity and uncertainty analyses were conducted on the estimated COP, and the results show that the COP is the most sensitive to the capital cost, discount rate, electricity price and plant lifetime. [ABSTRACT FROM AUTHOR]

The development of a cost structure for energy storage systems (ESS) has received limited attention. In this study, we developed data-intensive techno-economic models to assess the economic feasibility of ESS. The ESS here includes pump hydro storage (PHS) and compressed air energy storage (CAES). The costs were developed using data-intensive bottom-up models. Scale factors were developed for each component of the storage systems. The life cycle costs of energy storage were estimated for capacity ranges of 98–491 MW, 81–404 MW, and 60–298 MW for PHS, conventional CAES (C-CAES), and adiabatic CAES (A-CAES), respectively, to ensure a market-driven price can be achieved. For CAES systems, costs were developed for storage in salt caverns hard rock caverns, and porous formations. The results show that the annual life cycle storage cost is $220–400 for PHS, $215–265 for C-CAES, and $375–480 per kW-year for A-CAES. The levelised cost of electricity is $69–121 for PHS, $58–70 for C-CAES, and $96–121 per MWh for A-CAES. C-CAES is economically attractive at all capacities, PHS is economically attractive at higher capacities, and A-CAES is not attractive at all. The developed information is helpful in making investment decision related to large energy storage systems. [ABSTRACT FROM AUTHOR]

The aim of this research is to model the market penetration of energy efficient appliances in the residential sector. The analysis focuses on six major appliances – refrigerators, freezers, clothes washers, clothes dryers, and ranges – to forecast their market penetration and market share during the years 2012–2050. Models were developed for each category using 22 years of historical data related to population, household income, immigration, and appliance price. These variables were selected based on the statistical tests of twelve macroeconomic variables. The market shares of high efficiency appliances were analyzed based on the related capital costs, operating costs, lifetime, and incentive. The results show that in Alberta the market penetration growth rate of dishwashers is higher than that of all other appliances, with a projected 30.52% increase between 2012 and 2050. The modeling results also indicate that the average annual energy consumption by refrigerators will decrease from 560.9 kWh in 2012 to 460.8 kWh in 2050, and this decrease indicates an annual energy efficiency improvement of 0.47%. In addition, the effect of an incentive on adopting high energy efficiency appliances and ultimately on energy efficiency improvement in Alberta is more effective for dishwashers and clothes washers. [ABSTRACT FROM AUTHOR]

Many studies have calculated deterministic point estimates of well-to-combustion (WTC) emissions of transportation fuels from crude oil in an attempt to determine which crude oils have lower or higher emissions. However, there is considerable variation in the published results, resulting in uncertainty. The purpose of this study is to identify GHG emissions ranges for five conventional and two unconventional crudes by performing an uncertainty analysis using an improved version of the FUN damental E N gineering Principl E s-based Mode L for Estimation of G reen H ouse G ases (FUNNEL-GHG). Distributions for key inputs in the Monte Carlo simulation were determined based on values obtained from the literature. Eleven scenarios were developed, nine historical and two current, the former using life-long average production data from the oil fields studied and the latter using recent production data to illustrate how WTC emissions change as the fields age. The mean WTC emissions ranges for the eleven scenarios are 97.5–140 gCO 2 eq/MJ. The uncertainty in the WTC emissions ranges from ±3% to ±11%. The largest source of uncertainty in the WTC emissions is from the venting, fugitive, and flaring volumes, fluid injection rates, and refinery yields. [ABSTRACT FROM AUTHOR]

China relies heavily on coal for power generation, and the demand for coal in a country of this size makes China the world's largest carbon dioxide emitter; hence China is pursuing greener pathways for power generation. Importing shale gas in the form of LNG from Canada is one such pathway. It starts with the recovery of shale gas in Canada and its export to China. This paper quantifies well-to-wire (WTW) greenhouse gas (GHG) emissions per kilowatt hour (kWh) of Canadian shale gas-fuelled electricity in China through models. WTW emissions include emissions from recovery, processing, transmission, liquefaction, marine shipping, re-gasification, power plant operations, and electricity transmission and distribution. Four Canadian shale gas reserves – Montney, Horn River, Liard, and Cordova – are considered. The results show that the WTW GHG emissions of Canadian shale gas-fired combined cycle technology range from 567 to 610 gCO 2 /kWh (57–62% of the GHG emissions from China's present coal-fired electricity), and total well-to-port (WTP) GHG emissions (emissions from recovery, processing, and transmission to a liquefaction facility) range from 7.68 to 13.4 gCO 2e /MJ. Sensitivity analysis results show that venting emissions during raw gas processing, flaring rates during well completion, and lifetime productivity of the gas significantly influence WTP emissions. [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]

The demand for hydrogen is likely to increase in the next decade to satisfy the projected growth of the bitumen upgrading industry in western Canada. This paper presents GHG (greenhouse gas) abatement costs and the GHG abatement potential in producing hydrogen from UCG (underground coal gasification) along with CCS (carbon capture and sequestration). Seven hydrogen production scenarios are considered to assess the competitiveness of implementing UCG compared to SMR (steam methane reforming). The analysis is completed through a LCA (life cycle assessment) of large-scale hydrogen production from UCG and SMR with and without CCS. Considering SMR technology without CCS as the base case, the GHG abatement costs of implementing the UCG-CCS technology is calculated to be in the range of 41–109 $CAD/tonne-CO 2 -eq depending on the transportation distance to the CCS site from the UCG-H 2 production plant. Life cycle GHG emissions are higher in UCG than in SMR. The GHG abatement costs for SMR-CCS-based scenarios are higher than for UCG-CCS-based scenarios; they range from 87 to 158 $CAD/tonne-CO 2 -eq in a similar manner to UCG-CCS. Consideration of revenues for selling the CO 2 captured for EOR (enhanced oil recovery) reduces the GHG abatement costs. An opportunity for revenue generation is realized in the UCG-CCS case. [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]

Emissions from crude recovery contribute significantly to the life cycle GHG (greenhouse gas) emissions of transportation fuels. Recovery emissions come from drilling and land use change, crude extraction, crude oil processing, venting, flaring, and fugitives. In this study an attempt has been made to provide a transparent quantification of GHG emissions from oil well drilling and land use change, crude recovery and associated gas and water treatment, and venting and flaring for five North American conventional crudes through the development of data-intensive engineering models. Estimates of emissions from crude extraction were made from recovery efficiency, the amount of energy used, and process fuel shares in extraction techniques. Extraction emissions vary from 1.24 g-CO2eq/MJ for Bow River heavy oil to 23 g-CO2eq/MJ for California's Kern County heavy oil. The amount of gas vented and flared per m3 of crude extracted was determined to quantify venting and flaring emissions. The amount of energy required for crude oil processing was quantified based on the properties of crude oil and different techniques applied in the oil fields. Of the five crudes we studied, California's Kern County heavy oil and Mars crude oil emit the highest and lowest emissions: 23.85 g-CO2eq/MJ and 3.94 g-CO2eq/MJ, respectively. [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]

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]

Abstract The cement industry is responsible for between 5% and 9% of global greenhouse gas (GHG) emissions. The increasing trend of GHG emissions from cement sector highlights the importance of GHG mitigation in this industry. In the current study, bottom-up energy modelling and scenario analyses were used to assess long-term GHG mitigation potential in the cement industry. The developed comprehensive, data-intensive, and technology-rich model is flexible and can be used to study the GHG mitigation potential in different regions. For the case study of Canada, a reference scenario along with 20 GHG emissions' reduction scenarios were developed in the Long-range Energy Alternative Planning (LEAP) model. For each scenario, cumulative energy saving and GHG reduction potential were analyzed. Furthermore, the net present value, cost of saved energy, and carbon were calculated to assess the economic performance of different scenarios. Carbon abatement cost curves were also developed using the GHG mitigation potential and the cost of implementing different energy efficiency options. Overall, compared to the reference scenario, the cumulative GHG mitigation potentials in the Canadian cement sector are 27 and 59 million tonnes CO 2 eq. by the years 2030 and 2050, respectively. More than 70% of the emissions' reduction is achievable with negative cost. Highlights • A bottom-up and technology-rich model is developed for the cement industry. • Energy consumption demand tree is used to analyze the energy intense sub-processes. • 20 scenarios are developed to assess the long-term energy saving and GHG mitigation. • Carbon abatement cost curves are developed to rank energy saving options. [ABSTRACT FROM AUTHOR]

An algal biorefinery approach is today's need for commercialization of microalgal biodiesel production. In the present study, an indoor photobioreactor with Chlorella minutissima was evaluated to upgrade biogas produced from anaerobic digestion of cow dung. The potential of C. minutissima was assessed in two different growth media viz. BG 11 and wastewater. The significant CO 2 absorption reported by C. minutissima was in the range of 75–85.4% at 1296 μmol m −2 s −1 of light intensity and 0.33 vol per volume per minute (vvm) gas flows. The present study demonstrated that there is an increase in methane content from 63.5 to 86.4% in the effluent biogas. The highest biomass productivity was observed at 1296 μmol m −2  s −1 light intensity with the same gas flow and the productivity of 0.18 gL −1 and 2.2 gL −1 in the BG11 medium and wastewater respectively. Further, we reported that total lipid content based on dry biomass of C. minutissima were 22.4% and 26% in the BG11 medium and wastewater, respectively. The gross calorific value of treated biogas was also higher (8.15 kWh m −3 and 8.63 kWh m −3 ) in both BG11 and wastewater, respectively. [ABSTRACT FROM AUTHOR]

With the growing number of electric vehicles in the transportation sector aimed at reducing greenhouse gas emissions, vehicle-to-grid (V2G) technology can play an important role in stabilizing electricity grids. An electric vehicle could be used as an energy storage system (ESS) that provides electricity to the grid when required. Several studies have evaluated the economic performance of different stationary ESSs; however, research that focuses on the V2G technology economic feasibility is scarce for cold climates. In this study, an engineering principles-based techno-economic model was developed to estimate the levelized cost of storage (LCOS) of V2G technology for energy arbitrage and frequency regulation. A model was also developed to predict the available energy and cost for V2G applications at various temperatures. Sensitivity and uncertainty analyses were performed to identify the key parameters that drive economic performance. The base case values of the LCOS are $230.88 and $329.93/MWh for energy arbitrage and frequency regulation, respectively. The key parameters are ambient temperature, battery cycle life, distance traveled per day, battery depth of discharge, battery capital cost, and electricity price. Considering the variabilities in these parameters, the probable ranges of the LCOS are $158-$290/MWh and $244-$485/MWh for energy arbitrage and frequency regulation, respectively. • The economic viability of a vehicle-to-grid (V2G) system was assessed. • A techno-economic model was developed to estimate the levelized cost of storage for energy arbitrage and frequency regulation. • The effect of temperature on vehicle-to-grid energy availability was studied. • The levelized cost of storage is from $158 to $290/MWh for energy arbitrage. • The levelized cost of storage is $244-$485/MWh for frequency regulation. [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]

The main purpose of this study is to develop a bottom-up life cycle assessment model to evaluate the greenhouse gas (GHG) emissions associated with the Canadian oil sands supply to China. Two pathways were considered. In pathway I, extracted bitumen is sent to Edmonton for upgrading and pipelined to the Westridge terminal near Vancouver, then shipped to a port in China. In pathway II, extracted bitumen is mixed with diluent, directly pipelined to the Westridge terminal, and shipped to China. The results from both the pipeline and the shipping models suggest that pathway I has better GHG emissions than pathway II on a per-barrel basis. GHG emissions are 2.4–3.5 times lower in pipelining synthetic crude oil (SCO) to Westridge than in pipelining dilbit, without and with a diluent return. The emissions range from 826 − 401 + 701 g CO 2 eq/bbl for SCO, 1819 − 719 + 1172 for dilbit without diluent return, and 2684 − 1065 + 1374 g CO 2 eq/bbl for dilbit with a diluent return. Shipping SCO has 15% fewer emissions than shipping dilbit. The shipping emissions are due to fuel use in the main engine. The emissions for shipping are 5536 − 914 + 966 g CO 2 /bbl for dilbit and 4034 − 822 + 899 g CO 2 /bbl for SCO. • GHG emission performances of Canadian oil sands supply to China were identified. • Pipeline GHG emissions range from 826 − 401 + 701 to 1819 − 719 + 1172 g CO 2 eq/bbl. • Shipping synthetic crude oil has 15% fewer GHG emissions than shipping dilbit. • Shipping GHG emissions ranges from 4034 − 822 + 899 to 5536 − 914 + 966 g CO 2 /bbl. • The synthetic crude oil supply pathway has a higher GHG performance than the dilbit. [ABSTRACT FROM AUTHOR]

Canada has many isolated communities that are not connected to the electrical grid. Most of these communities meet their electricity demand through stand-alone diesel generators. Diesel generators have economic and environmental concerns that can be minimized by using hybrid renewable energy technologies. This study aims to assess the implementation of a hybrid energy system for an off-grid community in Canada and to propose the best hybrid energy combination to reliably satisfy electricity demand. Seven scenarios were developed: 1) 100% renewable resources, 2) 80% renewable resources, 3) 65% renewable resources, 4) 50% renewable resources, 5) 35% renewable resources, 6) 21% renewable resources, and 7) battery-diesel generators (0% renewable resources). A case study for the remote community of Sandy Lake, Ontario, was conducted. Hybrid systems were chosen to meet the requirements of a 4.4 MWh/day primary load with a 772 kW peak load. Sensitivity analyses were carried out to assess the impact of solar radiation, wind speed, diesel price, CO 2 penalty cost, and project interest rate on optimum results. A GHG (greenhouse gas) abatement cost was assessed for each scenario. Considering GHG emission penalty cost, the costs of electricity for the seven scenarios are $1.48/kWh, $0.62/kWh, $0.54/kWh, $0.42/kWh, $0.39/kWh, $0.37/kWh, and $0.36/kWh. [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]

Conventional agriculture is energy and carbon intensive. Single and double-crop basis residue-mulching in zero-tilled crop-sequences may minimize carbon-footprint with improved crop and energy productivity in water-scarce ecologies. Zn-fertilization is also vital for drought-stress tolerance besides enhanced productivity and quality in Zn-deficient arid-soils. Hence, we compared the single and double-crop basis residue-mulching alongwith Hydrogel and Zn-fertilization in zero-tilled pigeonpea-wheat system. Results showed that double-crop residue-mulching + Hydrogel exhibited ∼22.3 and 17.1% higher system-productivity over no-residue and single-crop residue-mulching plots while maintaining higher net-returns (1315 US$/ha). Crop-residue covering consumed considerable energy (77.3–89.1% of total consumption) and carbon (5–10 folds). Thick residue-cover (8 t/ha/year) under double-crop residue-mulching + Hydrogel exhibited significantly higher energy-output (238,328 MJ ha−1), energy-intensiveness (107.3 MJ/US$) and specific energy (20.15 MJ kg−1) compared to single-crop residue-mulching; whereas energy-use efficiency, energy productivity and profitability were higher under no-residue cover. Zn-fertilization (5 kg ha−1) alongwith Zn-solubilizer in both crops also enhanced the biomass and energy productivity over sole-Zn or no-Zn. Interestingly, carbon footprints increased with residue-covering (4–8 t/ha/year) while least under no-residues. Therefore, farmers should preserve a balance while mulching the residues in single or both crops besides necessitating Zn-fertilization in Zn-deficient arid and semi-arid regions where livestock equally competes for residues as quality fodder. • Higher yield, energy output and profits in double-crop residue mulching in zero-tilled (ZT) sequence. • Zn plus Zn-solubilizer enhanced yield, profits and energy-use over sole use or no-Zn. • Crop residue covering consumed higher energy and carbon input and production costs. • Single-crop residue mulching more carbon and energy-use efficient over double-crop mulched plots. • Higher energy and carbon use efficiency in no-residue plots in ZT system. [ABSTRACT FROM AUTHOR]

Greenhouse gas (GHG) mitigation opportunities from emerging in situ mining technologies in oil sands production can play a role in reducing global warming. There is limited research on quantitative assessments of the penetration of emerging oil sands technology in the energy sector. This study addresses this gap by developing a novel framework (MAPL-OET) to assess the market penetration of emerging oil sands extraction technologies. The framework is robust and data-intensive as it combines diffusion models, econometrics models, cost models, and energy-economy equilibrium models. The combined model evaluates the adoption of new energy technologies resulting from carbon price measures and other economic factors, as well as the GHG mitigation potential in the oil sands sector. The accumulated GHG mitigation potential from high carbon and BAU scenarios (i.e., a carbon price of $30/tonne of CO 2 in 2030, increasing at a rate of 4%/yr to reach about $105/tonne of CO 2) was estimated to be 192.8 Mt of CO 2 eq between 2018 and 2050. New extraction technologies also improve average energy intensities by 1.3% annually in the high carbon price scenarios. The developed new framework can help public and private organizations to achieve energy or environmental targets. • The analysis focuses on oil sands extraction technologies. • A new combined method is developed and used for market penetration modeling. • Efficient in situ bitumen mining technologies shares are modeled from 2020 to 2050. • Effects of carbon price on energy efficiency improvement are analyzed. • Annual energy efficient improvement is evaluated. [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]