Energy consumption and greenhouse gas emissions in upgrading and refining of Canada's oil sands products

Life cycle assessment of greenhouse gas emissions from Canada's oil sands-derived transportation fuels

Energy consumption and greenhouse gas emissions in the recovery and extraction of crude bitumen from Canada’s oil sands

Greenhouse gas (GHG) regulations affecting U.S. transportation fuels require holistic examination of the life-cycle emissions of U.S. petroleum feedstocks. With an expanded system boundary that included land disturbance-induced GHG emissions, we estimated well-to-wheels (WTW) GHG emissions of U.S. production of gasoline and diesel sourced from Canadian oil sands. Our analysis was based on detailed characterization of the energy intensities of 27 oil sands projects, representing industrial practices and technological advances since 2008. Four major oil sands production pathways were examined, including bitumen and synthetic crude oil (SCO) from both surface mining and in situ projects. Pathway-average GHG emissions from oil sands extraction, separation, and upgrading ranged from ∼6.1 to ∼27.3 g CO2 equivalents per megajoule (in lower heating value, CO2e/MJ). This range can be compared to ∼4.4 g CO2e/MJ for U.S. conventional crude oil recovery. Depending on the extraction technology and product type output of oil sands projects, the WTW GHG emissions for gasoline and diesel produced from bitumen and SCO in U.S. refineries were in the range of 100-115 and 99-117 g CO2e/MJ, respectively, representing, on average, about 18% and 21% higher emissions than those derived from U.S. conventional crudes. WTW GHG emissions of gasoline and diesel derived from diluted bitumen ranged from 97 to 103 and 96 to 104 g CO2e/MJ, respectively, showing the effect of diluent use on fuel emissions.

Pitched battles are a regular occurrence in northern Alberta, Canada, as development of the province’s oil sands continues to expand. One ongoing battle—with another salvo launched in February 2011 with the leak of a European Commission report1—concerns how dirty oil sands are, relative to other fuels. Another concerns the influence of the oil sands industry in monitoring its own activity.2 In an effort to cut through the rhetoric of health advocates, industry representatives, environmentalists, government officials, and local residents, the Royal Society of Canada (RSC) selected and covered expenses for an expert panel to winnow out the facts. In a report issued 15 December 20103 the panel cited substantial evidence that efforts to extract oil from the Alberta deposits have degraded air, land, and water quality to varying degrees. The extent of the degradation is sometimes controversial; water quality data, in particular, are subject to differing interpretations and attributions of causality. However, the panel says that, based on publicly available evidence, there appear to be no significant human health threats to the general population either now or from development anticipated in the next decade or so. But the panel also warns that their conclusions come with a major caveat: there are major gaps in health and environmental data, risk assessments, government oversight, information transparency, industry efforts, and disaster preparedness. The health of the region could hinge on these gaps being addressed, particularly since, according to Travis Davies, a spokesman for the Canadian Association of Petroleum Producers, 97% of projected oil extraction and processing is still to come. After the RSC panel reviewed reams of publicly available information on factors such as health status, air and water pollution, greenhouse gas emissions, land disturbance, and energy and water consumption, it concluded that “[t]he claim by some critics of the oil sands industry that it is the most environmentally destructive project on earth is not supported by the evidence. However, for Canada and Alberta, the oil sands industry involves major environmental issues on many fronts which must be addressed as a high priority.”3p293

Energy infrastructure modeling for the oil sands industry: Current situation

The magnitude of Canada’s oil sands reserves, their rapidly expanding and energyintensive production, combined with existing and upcoming greenhouse gas (GHG)emissions regulations motivate an evaluation of oil sands-derived fuel productionfrom a life cycle perspective. Thirteen studies of GHG emissions associated withoil sands operations are reviewed. The production of synthetic crude oil (SCO)through surface mining and upgrading (SM&Up) or in situ and upgrading (IS&Up)processes is reported to result in emissions ranging from 62 to 164 and 99 to176 kgCO2eq/bbl SCO, respectively (or 9.2–26.5 and16.2–28.7 gCO2eq MJ−1 SCO, respectively),compared to 27–58 kgCO2eq/bbl (4.5–9.6 gCO2eq MJ−1) of crude for conventional oil production. The difference in emissions intensity betweenSCO and conventional crude production is primarily due to higher energy requirements forextracting bitumen and upgrading it into SCO. On a ‘well-to-wheel’ basis, GHG emissionsassociated with producing reformulated gasoline from oil sands with current SM&Up,IS&Up, and in situ (without upgrading) technologies are 260–320, 320–350, and270–340 gCO2eq km−1, respectively,compared to 250–280 gCO2eq km−1 for production from conventional oil. Some variation between studies is expected due todifferences in methods, technologies studied, and operating choices. However, themagnitude of the differences presented suggests that a consensus on the characterization oflife cycle emissions of the oil sands industry has yet to be reached in the public literature.Recommendations are given for future studies for informing industry and governmentdecision making.

As traditional petroleum supplies dwindled and prices soared over the past few years, oil companies have shifted their attention to oil sands, a mix of sand, water, and a heavy, viscous hydrocarbon called bitumen that can be converted to oil. With the plunge in oil prices in fall 2008, many producers began canceling or postponing plans to expand oil sands development projects, but this turn of events could yet reverse, as Canada’s vast oil sands deposits are lauded as a secure source of imported oil for the United States. At the same time, however, oil sands present troubling questions in terms of the environmental health effects associated with their development.

North America is in the midst of an energy revolution1—centered on unconventional petroleum (i.e., oil shale and oil sands) and unconventional natural gas (i.e., gas shale). Unfortunately, this revolution threatens to completely unhinge the global climate.2 This concern is especially acute with the Canadian oil (or tar) sands. The Canadian tar sands are a high carbon substitute for crude oil (i.e., conventional petroleum).3 (The Canadian oil sands are reputed to hold 170 billion barrels of petroleum.4) Bringing the oil sands to market significantly contributes to the global warming phenomenon in two ways.5 First, oil sands are "processed" onsite. Oil sands (a.k.a. bitumen) is diluted into dilbit (diluted bitumen) for purposes of transportation, and this requires energy—which results in greenhouse gas emissions.6 Second, apart from the energy used to make the oil sands transportable, more energy is needed to refine the tar sands into end use products (e.g., jet fuel) than is used to refine most conventional crude. The extra energy required to refine oil sands results in additional greenhouse gas emissions.7KeywordsUrban SprawlConsumer DurableCarter AdministrationConventional PetroleumAmerican EmpireThese keywords were added by machine and not by the authors. This process is experimental and the keywords may be updated as the learning algorithm improves.

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.

The development of a techno-economic model for the extraction, transportation, upgrading, and shipping of Canadian oil sands products to the Asia-Pacific region

A life cycle-based model, OSTUM (Oil Sands Technologies for Upgrading Model), which evaluates the energy intensity and greenhouse gas (GHG) emissions of current oil sands upgrading technologies, is developed. Upgrading converts oil sands bitumen into high quality synthetic crude oil (SCO), a refinery feedstock. OSTUM's novel attributes include the following: the breadth of technologies and upgrading operations options that can be analyzed, energy intensity and GHG emissions being estimated at the process unit level, it not being dependent on a proprietary process simulator, and use of publicly available data. OSTUM is applied to a hypothetical, but realistic, upgrading operation based on delayed coking, the most common upgrading technology, resulting in emissions of 328 kg CO2e/m3 SCO. The primary contributor to upgrading emissions (45%) is the use of natural gas for hydrogen production through steam methane reforming, followed by the use of natural gas as fuel in the rest of the process units' heaters (39%). OSTUM's results are in agreement with those of a process simulation model developed by CanmetENERGY, other literature, and confidential data of a commercial upgrading operation. For the application of the model, emissions are found to be most sensitive to the amount of natural gas utilized as feedstock by the steam methane reformer. OSTUM is capable of evaluating the impact of different technologies, feedstock qualities, operating conditions, and fuel mixes on upgrading emissions, and its life cycle perspective allows easy incorporation of results into well-to-wheel analyses.

We present a statistically enhanced version of the GreenHouse gas emissions of current Oil Sands Technologies model that facilitates characterization of variability of greenhouse gas (GHG) emissions associated with mining and upgrading of bitumen from Canadian oil sands. Over 30 years of publicly available project-specific operating data are employed as inputs, enabling Monte Carlo simulation of individual projects and the entire industry, for individual years and project life cycles. We estimate that median lifetime GHG intensities range from 89 to 137 kg CO2eq/bbl synthetic crude oil (SCO) for projects that employ upgrading. The only project producing dilbit that goes directly to a refinery has a median lifetime GHG intensity of 51 kg CO2eq/bbl dilbit. As SCO and dilbit are distinct products with different downstream processing energy requirements, a life cycle assessment ("well to wheel") is needed to properly compare them. Projects do not reach steady-state in terms of median GHG intensity. Projects with broader distributions of annual GHG intensities and higher median values are linked to specific events (e.g., project expansions). An implication for policymakers is that no specific technology or operating factor can be directly linked to GHG intensity and no particular project or year of operation can be seen as representative of the industry or production technology.

Alberta's reserves of conventional erode oil, natural gas, heavy oil and oil sands represent more than 90% of Canada's total energy reserves in these categories. Of these heavy oil and oil sands. constitute more than 60% of Alberta's total. Current forecast point out a decline in conventional reserves as production exceeds new discoveries. This trend is expected to continue with fewer and smaller prospects remaining to be discovered. The decline in conventional reserves, however, could be made up by an orderly development of oil sands and heavy oil projects. Based on the magnitude of the unconventional reserves, (approximately 300 billion tonnes bitumen in place), one could observe that the prospects for maintaining Canada's energy self-sufficiency are contingent on the production of heavy hydrocarbons from oil sands and heavy oil. The development of new surface mineable oil sands projects require large capital investment and their operations are labour intensive. Therefore, the total cost of synthetic crude production from new projects is not competitive with the most conventional production operations. However, oil sands have no exploration costs and present minimal exploration risks. In addition, the experience gained in oil sands operations during the last two decades has reduced actual production costs by one-half; but, the cost discrepancy between the conventional oil and synthetic crude oil, is significant enough to justify serious R&D efforts in oil sands. This paper points out the importance of oil sands for the future energy supply in Canada and identifies the R&D as the key to further commercial development of this valuable resource. The paper proposes a methodology and a set of criteria for determining technology requirements and ranking them. Finally, it provider a select list of areas for technology development and offers a series of practical recommendations. Introduction The rationale behind the Alberta Chamber of Resources interest in the long-term technology requirements is the recognition of the fact that the future economic competitiveness of bitumen or synthetic crude production from oil sands will be contingent upon further improvements in both capital and operating costs. Any significant cost reduction, in turn, can only be achieved through advancements and breakthroughs in technology. The Chamber recognizes the progress recorded in recent years and the current R&D efforts in diverse area of oil sands technologies. However, the Chamber is not aware of the existence of a long-term plan for oil sands R&D to guide the funding agencies and the technology developers in identifying the needs and determining the priorities. Therefore, the Chamber is concerned that in the absence of an over-all R&D road map, sufficient funds may not be available or the precious few funds that are available, may not be allocated to the appropriate R&D programs, The ACR Oil Sands Task Force's identification of the future technology requirements is based on a projected scenario which points out the importance of fossil fuels well beyond the year 2010. In this scenario, western Canada's oil sands and coal resources are predicted to supply a major portion of Canada's energy requirements throughout the 2lst century.

In this paper, we used the life-cycle analysis (LCA) method to evaluate the energy consumption and greenhouse gas (GHG) emissions of natural gas (NG) distributed generation (DG) projects in China. We took the China Resources Snow Breweries (CRSB) NG DG project in Sichuan province of China as a base scenario and compared its life cycle energy consumption and GHG emissions performance against five further scenarios. We found the CRSB DG project (all energy input is NG) can reduce GHG emissions by 22%, but increase energy consumption by 12% relative to the scenario, using coal combined with grid electricity as an energy input. The LCA also indicated that the CRSB project can save 24% of energy and reduce GHG emissions by 48% relative to the all-coal scenario. The studied NG-based DG project presents major GHG emissions reduction advantages over the traditional centralized energy system. Moreover, this reduction of energy consumption and GHG emissions can be expanded if the extra electricity from the DG project can be supplied to the public grid. The action of combining renewable energy into the NG DG system can also strengthen the dual merit of energy conservation and GHG emissions reduction. The marginal CO2 abatement cost of the studied project is about 51 USD/ton CO2 equivalent, which is relatively low. Policymakers are recommended to support NG DG technology development and application in China and globally to boost NG utilization and control GHG emissions.

Impressive advances in technology have enabled the production of a third of Canada's oil requirements from the oil sands and heavy oil deposits mainly located in the province of Alberta. This paper reviews the geological setting of the deposits and the various methods of extracting the bitumen, surfaced mined or in-situ. The principal processes to upgrade the raw bitumen product into a synthetic crude oil for pipelining to refineries is considered. Though many advances have been made, to realize the full potential of these reserves in the face of declining conventional oil supplies, a recommendation is made for an environment supporting a stable sustained effort to continue technological improvement toward developing and upgrading these vast resources. Introduction Canada leads the world in the development of its oil sands and heavy oil resources. About one-third of the country's supply of oil comes from heavy oil deposits and from the oil sands deposits located in the province of Alberta. Production of bitumen surface mined from the Athabasca deposit and upgraded to light sweet synthetic crude oil, provides 35,800 m3 (225,000 barrels) per day or over 15% of the country's petroleum needs. In-situ production of raw bitumen from deep oil sands deposits results in an additional 15,600 m3 (98,000 barrels) per day. These large-scale, technically advanced operations provide a benchmark against which further developments in Canada and elsewhere may be compared. At the same time, while bitumen production is increasing, light oil production in Alberta appears to have peaked. The National Energy Board of Canada has estimated that conventional oil production in Canada will decline by close to 80,000 m3 (half a million barrels) per day over the next decade. Increasingly, the vast Alberta oil sands bitumen reserves will be required to fill the future shortfalls in energy availability. Oil sands, heavy oil and enhanced oil recovery represent the future of the petroleum industry in Alberta to offset the slow decline in conventional oil production (Fig. I). While much research and development is required to improve the technology employed in Canada's oil sands in order to maintain a competitive industry in the future, the industry is operating successfully today. There are two large-scale surface mining operations near Fort McMurray, Alberta, which each have associated upgrading facilities which convert all of their recovered bitumen to a light, low sulphur, residuum free synthetic crude oil. The first of these is operated by Suncor Inc. (formerly Great Canadian Oil Sands Ltd.). But the largest of the operations is the Syncrude joint venture, a surface mining and upgrading complex which has now been in operation for 12 years. Since the year following start-up, the operation has generated a positive cash flow in all years but one while at the same time financing a 50% increase in capacity from cash flow during 1983 to 1988. Over C$1,000 million has been generated as a 50% share of deemed net profit by the operation and paid to the Government of Alberta in place of resource royalty.