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[en] 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
[en] The power cost and optimum plant size for power plants using three biomass fuels in western Canada were determined. The three fuels are biomass from agricultural residues (grain straw), whole boreal forest, and forest harvest residues from existing lumber and pulp operations (limbs and tops). Forest harvest residues have the smallest economic size, 137 MW, and the highest power cost, $63.00 MWh-1 (Year 2000 US$). The optimum size for agricultural residues is 450 MW (the largest single biomass unit judged feasible in this study), and the power cost is $50.30 MWh-1. If a larger biomass boiler could be built, the optimum project size for straw would be 628 MW. Whole forest harvesting has an optimum size of 900 MW (two maximum sized units), and a power cost of $47.16 MWh-1 without nutrient replacement. However, power cost versus size from whole forest is essentially flat from 450 MW ($47.76 MWh-1) to 3150 MW ($48.86 MWh-1), so the optimum size is better thought of as a wide range. None of these projects are economic today, but could become so with a greenhouse gas credit. All biomass cases show some flatness in the profile of power cost vs. plant capacity. This occurs because the reduction in capital cost per unit capacity with increasing capacity is offset by increasing biomass transportation cost as the area from which biomass is drawn increases. This in turn means that smaller than optimum plants can be built with only a minor cost penalty. Both the yield of biomass per unit area and the location of the biomass have an impact on power cost and optimum size. Agricultural and forest harvest residues are transported over existing road networks, whereas the whole forest harvest requires new roads and has a location remote from existing transmission lines. Nutrient replacement in the whole forest case would make power from the forest comparable in cost to power from straw
[en] Highlights: • We develop water consumption and withdrawals coefficients for coal power generation. • We develop life cycle water footprints for 36 coal-based electricity generation pathways. • Different coal power generation technologies were assessed. • Sensitivity analysis of plant performance and coal transportation on water demand. - Abstract: This paper aims to develop benchmark coefficients for water consumption and water withdrawals over the full life cycle of coal-based power generation. This study considered not only all of the unit operations involved in the full electricity generation life cycle but also compared different coal-based power generating technologies. Overall this study develops the life cycle water footprint for 36 different coal-based electricity generation pathways. Power generation pathways involving new technologies of integrated gasification combined cycle (IGCC) or ultra supercritical technology with coal transportation by conventional means and using dry cooling systems have the least complete life cycle water-demand coefficients of about 1 L/kW h. Sensitivity analysis is conducted to study the impact of power plant performance and coal transportation on the water demand coefficients. The consumption coefficient over life cycle of ultra supercritical or IGCC power plants are 0.12 L/kW h higher when conventional transportation of coal is replaced by coal-log pipeline. Similarly, if the conventional transportation of coal is replaced by its transportation in the form of a slurry through a pipeline, the consumption coefficient of a subcritical power plant increases by 0.52 L/kW h
[en] 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 (bblW) per barrel of refined oil (bblBUR) and 2.87–5.16 bblW/bblBUR 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 bblW/bblB, upgrading be 0.87 bblW/bblU, and refining to be 1.52 bblW/bblR. - Highlights: • The life cycle water footprint for oil sands-based transportation fuel was studied. • Water footprints for bitumen extraction, upgrading, and refining were developed. • The water consumption coefficients for the complete life cycle of oil sands ranges from 2.08 to 4.19 bbl/bbl refined oil. • Surface mining has a higher water consumption coefficient than steam-assisted gravity drainage.
[en] In this article, we present an in-depth review of the phenomenon of negative magnetization (or magnetization sign reversal) with an up-to-date literature. We have described numerous experimental examples of the phenomenon, involving a variety of magnetically ordered systems, where it does not arise due to diamagnetism. The present review discusses physics principles for the sign reversal of magnetization under the following mechanisms: (a) negative exchange coupling among ferromagnetic sublattices, (b) negative exchange coupling among canted antiferromagnetic sublattices, (c) negative exchange coupling among ferromagnetic/canted-antiferromagnetic and paramagnetic sublattices, (d) imbalance of spin and orbital moments, and (e) interfacial exchange coupling between ferromagnetic and antiferromagnetic phases. We have put forward the roles of crystal structure, crystallite type (single crystal, bulk polycrystalline, thin film, and nanoparticle), lattice defect, electronic or chemical phase separation, magnetic anisotropy, and magnetic exchange interactions in the magnetization reversal. This review validates the mean field theory, given by L. Néel (1948), for an explanation of the negative magnetization under the category (a). We also bring out the necessity of further theoretical work to account for the other categories, (b)–(e). The present review also describes the importance of various magnetization measurement protocols for the occurrence of the magnetization reversal. Finally, we have pointed out the tunability aspect of the phenomenon. We conclude that the practical utilization of this phenomenon in magnetic memory, and magnetocaloric and spin resolving devices might be realized by choosing appropriate and well characterized materials whose compensation temperature can be tuned to room temperature
[en] Highlights: • Water consumption and withdrawals coefficients for renewable power generation were developed. • Six renewable energy sources (biomass, nuclear, solar, wind, hydroelectricity, and geothermal) were studied. • Life cycle water footprints for 60 electricity generation pathways were considered. • Impact of cooling systems for some power generation pathways was assessed. - Abstract: Renewable energy technology-based power generation is considered to be environmentally friendly and to have a low life cycle greenhouse gas emissions footprint. However, the life cycle water footprint of renewable energy technology-based power generation needs to be assessed. The objective of this study is to develop life cycle water footprints for renewable energy technology-based power generation pathways. Water demand is evaluated through consumption and withdrawals coefficients developed in this study. Sixty renewable energy technology-based power generation pathways were developed for a comprehensive comparative assessment of water footprints. The pathways were based on the use of biomass, nuclear, solar, wind, hydroelectricity, and geothermal as the source of energy. During the complete life cycle, power generation from bio-oil extracted from wood chips, a biomass source, was found to have the highest water demand footprint and wind power the lowest. During the complete life cycle, the water demand coefficients for biomass-based power generation pathways range from 260 to 1289 l of water per kilowatt hour and for nuclear energy pathways from 0.48 to 179 l of water per kilowatt hour. The water demand for power generation from solar energy-based pathways ranges from 0.02 to 4.39 l of water per kilowatt hour, for geothermal pathways from 0.04 to 1.94 l of water per kilowatt hour, and for wind from 0.005 to 0.104 l of water per kilowatt hour. A sensitivity analysis was conducted with varying conversion efficiencies to evaluate the impact of power plant performance on water demand. Cooling systems used in power generation plants were also studied and include once-through, recirculating, dry, and hybrid cooling. When only the power generation stage is considered, hydroelectricity and nuclear power generation with once-through cooling systems showed the highest water consumption (68 l of water per kilowatt hour) and water withdrawals coefficients (178 l of water per kilowatt hour), respectively.
[en] Highlights: • Water consumption and withdrawals coefficients for gas-fired power generation. • Life cycle water footprints for 18 gas-fired electricity generation pathways. • Different gas-fired power generation technologies were assessed. • Sensitivity analysis on water demand for upstream and power generation stages. - Abstract: The key objective of this paper is to develop a benchmark for water demand coefficients of the complete life cycle of natural gas-fired power generation. Water demand coefficients include water consumption and water withdrawals for various stages of natural gas production as well as for power generation from it. Pathways were structured based on the unit operations of the types of natural gas sources, power generation technologies, and cooling systems. Eighteen generic pathways were developed to comparatively study the impacts of different unit operations on water demand. The lowest life cycle water consumption coefficient of 0.12 L/kW h is for the pathway of conventional gas with combined cycle technology, and dry cooling. The highest life cycle consumption coefficient of 2.57 L/kW h is for a pathway of shale gas utilization through steam cycle technology and cooling tower systems. The water consumption coefficient for the complete life cycle of cogeneration technology is in the range 0.07–0.39 L/kW h and for withdrawals ranged 0.10–14.73 L/kW h.
[en] 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. - Highlights: • This study estimates the net energy ratio and greenhouse gas emissions in production and utilization of renewable diesel. • The life cycle approach has been used in this study using canola and camelina as feedtocks. • Several scenarios were developed to study the impacts of variations in unit operations on net energy ratio and emissions. • HDRD from both crops appears to be more sustainable than fossil diesel
[en] 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. - Abstract: This paper examines the techno-economic viability of hydrogen production from underground coal gasification (UCG) in Western Canada, for the servicing of the oil sands bitumen upgrading industry. Hydrogen production for bitumen upgrading is predominantly achieved via steam methane reforming (SMR); which involves significant greenhouse gas (GHG) emissions along with considerable feedstock (natural gas) cost volatility. UCG is a formidable candidate for cost-competitive environmentally sustainable hydrogen production; given its negligible feedstock cost, the enormity of deep coal reserves in Western Canada and the favourable CO2 sequestration characteristics of potential UCG sites in the Western Canadian sedimentary basin (WCSB). Techno-economic models were developed for UCG and SMR with and without CCS, to estimate the cost of hydrogen production including delivery to a bitumen upgrader. In this paper, at base case conditions, a 5% internal rate of return (IRR) differential between UCG and SMR was considered so as to account for the increased investment risk associated with UCG. The cost of UCG hydrogen production without CCS is estimated to be $1.78/kg of H2. With CCS, this increases to range of $2.11–$2.70/kg of H2, depending on the distance of the site for CO2 sequestration from the UCG plant. The SMR hydrogen production cost without CCS is estimated to be $1.73/kg of H2. In similar fashion to UCG, this rises to a range of $2.14 to $2.41/kg of H2 with the consideration of CCS. Lastly, for hydrogen production without CCS, UCG has a superior cost competitiveness in comparison to SMR for an IRR differential less than 4.6%. This competitive threshold rises to 5.4% for hydrogen production with CCS
[en] 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. - Highlights: • An integrated hydropower-hydrogen plant model is developed. • Plant configurations were considered in a liberalized electricity market. • Optimum electrolyser farm size is 3496 kW × 90 units. • Minimum H_2 cost achieved varies from $1.18/kg H_2 – $2.43/kg H_2. • Hydrogen from hydropower is competitive with SMR/SMR-CCS.