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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]

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]

There is a high demand for natural gas in the Asia-Pacific region. Most of this gas is exported from the Middle East, Australia, Indonesia, and Malaysia. There is interest in the Asia-Pacific to diversify its import portfolio. From a Canadian perspective, there are abundant resources of natural gas in Western Canada, and countries in the Asia-Pacific are potential customers. This paper develops the cost of shipping a unit of natural gas (in liquefied form) from proposed liquefaction facilities in Western Canada to liquefied natural gas (LNG) re-gasification terminals in Asia-Pacific countries (Japan, China, and India). Fundamental engineering principles-based models were developed to estimate costs. A comparative analysis of delivery costs to Japan, China, and India is presented. To account for various propulsion systems available for LNG carriers, five scenarios were developed. Calm water resistance for the two different categories of LNG carriers was estimated. These estimates were used to determine the required propulsion power needed for an LNG carrier at a given speed and to select the appropriate main engine. The results of this study show that shipping costs to Japan range from 51–95 U.S. cents/GJ depending on the type of propulsion system selected and for an average transport distance of 7793 km. The shipping costs to China and India range from 59–113 U.S. cents/GJ and 98–197 U.S. cents/GJ for an average transport distance of 9475 km and 17,035 km, respectively. The results show that a propulsion system burning only natural gas as primary fuel is the most economical scenario, while a propulsion system based on pure marine diesel oil is the least economical. In addition to a sensitivity analysis, a risk analysis was conducted to identify the range of shipping costs in each scenario with their occurrence probability measure. [ABSTRACT FROM AUTHOR]

Hydrogen is a key input to industrial processes. In western Canada, there is a significant demand for hydrogen for industrial purposes, both to upgrade bitumen and as a chemical agent. The key driver for this research is the need to assess options for the energy industry to lower its carbon footprint by using hydrogen produced from renewable sources. The environmental impacts associated with hydrogen production through water electrolysis using the electricity generated from a wind power plant are evaluated in this paper. A life cycle assessment was done to determine the greenhouse gas (GHG) emissions per unit mass of produced hydrogen by considering the emissions starting from the extraction of wind energy to the production of hydrogen. An uncertainty analysis was conducted to assess the effects of variations of different input parameters on the GHG footprint of hydrogen produced from wind. The total GHG emissions of a wind-based hydrogen production plant are estimated to be 0.68 ± 0.05 kg CO 2 eq./kg H 2 , 65% of which are from the construction of the wind power system. The results are compared with those of conventional fossil fuel-based systems. The overall GHG emissions from wind-based hydrogen production are about 94% lower than those associated with hydrogen production through steam methane reforming (SMR). Natural gas-based hydrogen production emissions are mainly found in the plant operation stage. For wind-to-hydrogen systems, the manufacturing and installation of the systems have significant environmental impacts. However, the hydrogen produced from wind energy can significantly reduce the GHG footprint of the energy industry. [ABSTRACT FROM AUTHOR]

Hydrogen production via steam methane reforming (SMR) dominates the supply to refining complexes worldwide, resulting in significant greenhouse gas (GHG) emissions. There is a considerable demand for clean hydrogen pathways that are economically competitive with SMR. The development of a 563 MW integrated wind-hydrogen model with energy storage is proposed. The model utilizes real-time wind energy data to ascertain the optimal size of the electrolyser, the number of electrolyser units and the battery (energy storage) capacity that will yield a minimum hydrogen production cost, whilst functioning in a liberalized electricity market with dynamic prices. The optimal plant configuration consists of 81 units of a 3496 kW (760 Nm 3 /hr) electrolyser and 360 MWh (60 units) of battery capacity. For the minimum hydrogen production cost determined ($9.00//kg H 2 ), the wind farm accounts for 63% of this cost. Hence, if existing wind farm assets are used, such that the investment cost of building the wind-hydrogen plant does not include the wind farm costs, the hydrogen production cost is reduced to $3.37/kg H 2 . For a particular electrolyser-battery configuration, it was observed that the minimum hydrogen production cost occurs when their respective capacity factors are approximately equivalent. The benefits of energy storage are limited by the decrease in overall plant efficiency, which results from the use of the battery. For the techno-economic conditions considered in this paper, hydrogen production costs from wind powered electrolysis ($3.37 to $9.00/kg H 2 ) are uncompetitive with SMR/SMR-CCS ($1.87 to $2.60/kg H 2 ). [ABSTRACT FROM AUTHOR]

Highlights: [•] A framework is developed for estimation of tortuosity factor for biomass transport. [•] GIS is used to calculate the tortuosity factor for western Canada. [•] Tortuosity factor for the Province of Alberta in Canada is in the range of 1–3.16. [•] This methodology helps in accurate assessment of biomass delivery cost. [ABSTRACT FROM AUTHOR]

Highlights: [•] Development of a techno-economic model for UCG-CCS and SMR-CCS. [•] Estimation of H2 production costs with and without CCS for UCG and SMR. [•] UCG is more economical for H2 production with CCS. [•] SMR is more cost efficient for H2 production without CCS. [•] Cost competiveness is highly sensitive to the IRR differential between UCG and SMR. [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]

Biomass is nearly carbon neutral and can be used for the production of various liquid fuels and chemicals. Decisions on biomass utilization should be based on the most economical and mature route. This study analyzes mountain pine beetle (MPB) killed wood as the feedstock for production of bio-ethanol and bio-oil and compares it with the direct combustion route to produce electricity. The MPB infestation of British Columbia’s (BC), a western province of Canada, forest has reached an epidemic proportion and is spread over an area of 10 millionha. According to the current estimates of BC‘s Ministry of Forests and Range, about 1 billion m3 of trees would be killed by MPB by 2013. This infestation would result in large scale loss of jobs and the standing dead trees are a fire hazard and if left unharvested will decay and release carbon back to the atmosphere. The cost of bio-ethanol production from a 2100dry tonne/day plant using the infested wood for two locations (one remote and other near the industry) in BC is in the range of C$0.37–C$0.40/l (C$1.40–C$1.51/gallon). Similarly, cost of bio-oil production from a 220dry tonne/day plant using the infested wood for same two locations in BC is in the range of C$0.27–C$0.29/l (C$1.02–C$1.09/gallon). The cost of producing electricity using this bio-oil is above C$100/MWh which is higher than the current power price in BC. This cost is also higher than the cost of production of electricity by direct combustion of infested wood in a boiler (C$68–C$74/MWh). [Copyright &y& Elsevier]