Canadian Oil Sands Industry Research Articles

The techno-economics of alternative CO2 transport systems and their application in the Canadian oil sands industry

Abstract The rise in GHG emissions from the oil sands industry has prompted government and industry to seek ways to reduce its CO 2 output. CCS is currently the leading option in Alberta. A key to making it viable is a system that allows multiple emitters to gather, capture, and transport their CO 2 to the best sinks, efficiently and economically. The oil sands are located in Northern Alberta. Geological formations suitable for CO 2 storage exist in the South-West region, ∼400 km from the sources. Implementing CCS will necessitate transporting roughly 30 megatonnes of CO 2 to suitable sinks. One of the best sinks is the underground aquifer in the Redwater Reef near Ft. Saskatchewan, with an estimated preliminary capacity of one gigatonne of CO 2 , or 37 years of CO 2 emissions from oil sands, at 2007 rates. In this study, we compare two schemes to transport CO 2 from oil sands operations by capturing CO 2 and: (1) transporting it in its supercritical state to storage in the Redwater Reef and (2) transporting it in solution to Redwater, regenerating the solvent on-site and storing the CO 2 in the Redwater Reef. The fugitive emissions of Case 1 are consistently higher than those of Case 2. This is due to the former’s electricity demands and the fact that the emissions associated with energy for solvent regeneration are not captured. Case 1 is more susceptible to electricity cost fluctuations than Case 2, but the latter is more susceptible to changes in the price of fuel. Although the CAPEX is similar for both, Case 2 benefits more from economies of scale than Case 1; the OPEX for Case 1 is 3.5% higher. The avoidance costs of Case 2 are lower on a gross basis (111 vs. 114 $/tonne CO 2 ) and on a net basis (327 vs. 851 $/tonne CO 2 ).

Optimizing energy production with integrated CCS technology for CO2 emissions mitigation in the Canadian oil sands industry

Abstract The forecasted energy production of oil sands operations in Alberta in the year 2030 were optimised under CO2 emissions constraints, using a mixed integer linear optimisation model. The model features a variety of technologies (with and without CO2 capture), including coal and natural gas power plants, IGCC, and oxyfuel plants. Hydrogen production technologies are steam methane reforming and coal gasification. The optimization is executed at increasing CO2 emissions reduction levels, yielding unique infrastructures that satisfy the energy demands of the oil sands industry at minimal cost. The economic and environmental impacts of the optimally chosen technologies on the forecasted operations of the oil sands industry in 2030 are thus determined. The maximum CO2 emissions reduction attainable by using CCS in the oil sands industry in 2030 is 39% with respect to a business-as-usual baseline. This CO2 reduction results in an energy cost increase of roughly 20% for synthetic crude and 2% for bitumen production. CO2 reductions ranging from 0–35% can be attained by optimising the energy infrastructures, yielding energy production cost reductions between 9%–18%. The maximum CO2 intensity reduction is 46% for synthetic crude and less than 3% for bitumen. Energy conversion and CO2 capture account for the bulk of the energy costs for synthetic crude whereas transport and storage combined contribute between 2.6% and 5% over the entire range of CO2 reductions. The optimal energy production technologies are strongly dependent on the CO2 reduction targets. Power production without capture, predominantly NGCC and supercritical coal technology, is optimal at CO2 reduction levels of up to 30%. At higher CO2 reductions, only NGCC with capture and Oxyfuel plants are optimal. H2 production via coal gasification is optimal for CO2 reduction levels of 35% and lower. Above 35% reduction, steam methane reforming with capture is the dominant technology.

Energy Optimization Model with CO 2-Emission Constraints for the Canadian Oil Sands Industry

In this paper, a model for optimizing energy production for oil sands operations is presented. The objective of the model is to minimize the total annual cost of supplying energy to the oil sands industry, subject to CO 2 emissions constraints. The energy is supplied in the form of power, hydrogen, steam, hot water, diesel, and process fuel. The model, which is named the energy optimization model (EOM), is conceived as an analytical and planning tool for the energy industry and government sectors. The EOM determines optimal combinations of power and hydrogen plants that satisfy given energy demands of oil sands operations, at minimal cost and with reduced CO 2 emissions. The EOM thus generates optimal energy infrastructures and quantifies the costs and emissions associated with energy production for bitumen and upgraded bitumen production. A case study is used to showcase the capabilities of the model and illustrate its applicability as a tool to develop and evaluate optimal CO 2 mitigation strategies in ...

Developing a dynamic systems model for the sustainable development of the Canadian oil sands industry

One technique in management science that can be applied for sustainability assessment is simulation modelling supported by statistical and uncertainty analyses. A dynamic system modelling approach has been developed to assess the sustainability of novel technologies and to analyse how these technologies can be exploited to meet the triple bottom line objectives of sustainability. A prototype model of the oil sands industry, comprising a suite of systems models representing important variables of the environment, society and economy, including their inter-linkages over time has been developed. These models are used to simulate possible scenarios for assessing novel and innovative technologies, which are capable of reducing resource consumptions and environmental emissions while meeting production targets and societal needs. There are two identified emerging technologies that have a high potential for lowering Greenhouse Gase emissions in the Canadian oil sands industry. Projected trends for natural gas consumption, water consumption, operating and supply costs, population and other quantitative indicators of sustainability were also analysed.

Modeling the Energy Demands and Greenhouse Gas Emissions of the Canadian Oil Sands Industry

In this study, the energy requirements associated with producing synthetic crude oil (SCO) and bitumen from oil sands are modeled and quantified, on the basis of current commercially used production schemes. The production schemes were (a) mined bitumen, upgraded to SCO; (b) thermal bitumen, upgraded to SCO; and (c) thermal bitumen, diluted. Additionally, three distinct bitumen-upgrading methods were modeled and incorporated into schemes a and b. In addition to energy demands, the model computes the greenhouse gas (GHG) emissions associated with supplying the energy required to produce bitumen and SCO. This study comprises two distinct situations. The first is the base case in which all the energy is produced using current technology, in the year 2003. The second situation is a future production scenario, where energy demands are computed for SCO and bitumen production levels corresponding to the years 2012 and 2030. The results from the base case include the energy demands for producing thermal bitumen and mined bitumen, upgraded to SCO. These demands are expressed in terms of amounts of hot water, steam, power, hydrogen, diesel fuel, and process fuel for upgrading processes. The model output indicates that the majority of the GHG emissions (70−80%) result during bitumen upgrading. Additionally, it was found that steam, hydrogen, and power are the most GHG-intensive energy inputs to the process, accounting for 80% of the GHG emissions in the base case. CO2 accounts for 95% of the total GHG, while methane and nitrous oxide are responsible for the remaining GHG emissions of all the producers in the base case. The energy demands for production estimates in the years 2012 and 2030 are also presented. Of all energy commodities, steam demands for thermal bitumen extraction, as well as hydrogen demands for upgrading are poised to multiply roughly 6-fold by 2030, with respect to 2003 levels. The model results reveal that electricity and steam demands for upgrading and mining operations will roughly double by 2012 and increase by a factor of 2.4 between 2012 and 2030.

A crash programme scenario for the Canadian oil sands industry

The report Peaking of World Oil Production: Impacts, Mitigation and Risk Management, by Robert L. Hirsch et al., concludes that Peak Oil is going to happen and that worldwide large-scale mitigation efforts are necessary to avoid its possible devastating effects for the world economy. These efforts include accelerated production, referred to as crash programme production, from Canada's oil sands. The objective of this article is to investigate and analyse what production levels that might be reasonable to expect from a crash programme for the Canadian oil sands industry, within the time frame 2006–2018 and 2006–2050. The implementation of a crash programme for the Canadian oil sands industry is associated with serious difficulties. There is not a large enough supply of natural gas to support a future Canadian oil sands industry with today's dependence on natural gas. It is possible to use bitumen as fuel and for upgrading, although it seems to be incompatible with Canada's obligations under the Kyoto treaty. For practical long-term high production, Canada must construct nuclear facilities to generate energy for the in situ projects. Even in a very optimistic scenario Canada's oil sands will not prevent Peak Oil. A short-term crash programme from the Canadian oil sands industry achieves about 3.6 mb/d by 2018. A long-term crash programme results in a production of approximately 5 mb/d by 2030.