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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]

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 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]

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]

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]