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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]

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]

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]