Energy infrastructure modeling for the oil sands industry: Current situation

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.

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

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

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.

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

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

Canadian conventional oil production is declining and any significant new conventional oil discoveries are located in remote, high cost frontier areas. Synthetic crude oil and bitumen production from the vast, known oil sands in Alberta could offset the decline. Although oil sands tend to be an expensive source of supply, their abundance and proximity to markets and industrial centres, as well as the significant potential for reducing production costs through technology improvements, make them attractive candidates for commercial development. For this to become reality, certain prerequisites need to be in place. Since oil sand leases were first granted in northeast Alberta in the late 1950s, only two major oil sands mining projects have been developed. Although several similar oil sands projects have been proposed since then, none hove proceeded much beyond the design stage. This paper reviews the development history and nature of oil sands mining projects, examines the requirements for major oil sands mining projects in Canada and the lessons leaned from previously proposed projects. The paper focusses on the impact that stakeholder commitment, appropriate fiscal terms, corporate financial strength, technology development and readiness, quality project development and operational excellence market understanding, resource quality and the balancing of resource development with environmental responsibility have on the feasibility of developing this resource. Introduction Over the next 15 years, production from Canada's conventional established oil reserves are expected to decline by up to 50%. New conventional oil discoveries in remote high-cost frontier areas and synthetic crude oil (SCO) and bitumen production from vast known oil sands resources could help to offset this decline. Already Alberta's oil sands are playing a significant role in meeting current energy demands. The combined bitumen and SCO production from these in situ and surface mining projects account for about 20% of Canada's daily oil production. Although the potential of the Athabasca oil sands has been known for more than 200 years, development of the resource did not begin until the 1930s. The first commercial project started production in 1967. In 1990, the Athabasca deposit, home of the Suncor Inc. and Syncrude Canada Ltd. commercial mining projects, was the source of 33 130 m3/d (208 390 bbl/d) of SCO or 13% of Canada's oil production. Since production from these two operations first began, six similar oil sands mining projects have been proposed. However, none have proceeded much beyond the design stage. The seventh project, the OSLO Project is in its pre-appropriation stage. The OSLO Project promises an additional 12 700 m3/d (80 000 bbl/d) of SCO or 5% of Canada's daily oil production. Development History Background Development of the Athabasca oil sands as a source of crude oil reserves has been slow. Research into the nature of the oil sands started in the early 1880s when researchers at the Geological Survey of Canada in Ottawa conducted an experiment to separate the bitumen from the sand using hot water.

Greenhouse gas (GHG) emissions associated with extraction of bitumen from oil sands can vary from project to project and over time. However, the nature and magnitude of this variability have yet to be incorporated into life cycle studies. We present a statistically enhanced life cycle based model (GHOST-SE) for assessing variability of GHG emissions associated with the extraction of bitumen using in situ techniques in Alberta, Canada. It employs publicly available, company-reported operating data, facilitating assessment of inter- and intraproject variability as well as the time evolution of GHG emissions from commercial in situ oil sands projects. We estimate the median GHG emissions associated with bitumen production via cyclic steam stimulation (CSS) to be 77 kg CO2eq/bbl bitumen (80% CI: 61-109 kg CO2eq/bbl), and via steam assisted gravity drainage (SAGD) to be 68 kg CO2eq/bbl bitumen (80% CI: 49-102 kg CO2eq/bbl). We also show that the median emissions intensity of Alberta's CSS and SAGD projects have been relatively stable from 2000 to 2013, despite greater than 6-fold growth in production. Variability between projects is the single largest source of variability (driven in part by reservoir characteristics) but intraproject variability (e.g., startups, interruptions), is also important and must be considered in order to inform research or policy priorities.

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.

The Canadian Energy Research Institute (CERI) completed a study for Atomic Energy of Canada Limited (AECL) that compares the economics of a modified ACR-700 Advanced ™ CANDU Reactor with the economics of a natural gas-fired facility to supply steam to a hypothetical Steam Assisted Gravity Drainage (SAGD) project located in northeastern Alberta. The results were initially presented at the Petroleum Society's Canadian International Petroleum Conference 2003, Calgary, Alberta, Canada, June 10 - 12, 2003. The comparison was made by using discounted cash-flow methodology to estimate the levelized unit cost of steam that could be supplied to the SAGD project from either a nuclear or a gas-fired facility. The unit cost of steam was determined by treating the steam supply facility as a standalone business; it would ensure that all costs are recovered including capital costs, operating costs, fuel costs, and a return on investment. The study indicated that steam supply from an ACR-700 nuclear facility is economically competitive with steam supply from a gas-fired facility. An examination of key variables indicated that the cost of steam from the nuclear facility is very sensitive to the capital cost of the facility, while the cost of steam from the gas-fired facility is very sensitive to the price of natural gas and possible Kyoto Protocol compliance costs. Introduction The Alberta Energy and Utilities Board (EUB) estimated that Alberta's oil sands deposits contain 258.9 109m3 of initial crude bitumen in-place and that over 10% of the initial crude bitumen in-place (28.39 109m3) is recoverable using either surface mining (5.59 109m3) or in situ recovery (22.80 109m3) techniques(1). At year-end 2003, only 2.4% (0.67 109m3) of the initial established reserves had been produced. The EUB reported that, in 2003, Alberta produced 153.2 103m3/d of crude bitumen, with surface mining accounting for 4% and in situ recovery for 36%. In the same year, non-upgraded bitumen and synthetic crude oil accounted for 53% of Alberta's total crude oil and equivalent production. The EUB reported that it expected total mined bitumen production to increase from 97.7 103m3/d in 2003 to 226 103m3/d by 2013, and in situ crude bitumen production to increase from 55.5 103m3/d in 2003 to 139 103m3/d by 2013. Total bitumen production in 2013, 365 103m3/d, would represent a 2.4 fold increase from 2003. Based on the configuration of currently operating projects, it is estimated that achieving this production level could require approximately 60 106m3/d of natural gas in 2013, a significant quantity relative to Alberta's remaining established reserves of 1,087.6 109m3 at yearend 2003 and total production of 140.6 109m3 that year (Reserve Production Ratio of 7.7 years). Using nuclear energy to generate steam would reduce the oil sands industry's reliance on limited natural gas resources, reduce its exposure to volatile natural gas prices, and reduce its greenhouse gas (GHG) emissions. The CERI study updates work carried out over the last two decades regarding the possible application of nuclear technology for oil sands development(2, 3).

Statistically enhanced model of oil sands operations: Well-to-wheel comparison of in situ oil sands pathways

Mitigating Curtailment and Carbon Emissions through Load Migration between Data Centers

Energy security and greenhouse gas reductions are thought to be two of the most urgent priorities for sustaining and improving the human condition in the future. Few places pit the two goals so directly in opposition to one another as the Alberta oil sands. Here, Canadian natural gas is burned in massive quantities to extract oil from one of North America’s largest native sources of carbon-intensive heavy oil. This conflict need not continue, however; non-emitting nuclear energy can replace natural gas as a fuel source in an economical and more environmentally sound way. This would allow for the continued extraction of transportation fuels without greenhouse gas emissions, while freeing up the natural gas supply for hydrogen feedstock and other valuable applications. Bitumen production in Alberta has expanded dramatically in the past five years as the price of oil has risen to record levels. This paper explores the feasibility and economics of using nuclear energy to power future oil sands production and upgrading activities, and puts forth several nuclear energy application scenarios for providing steam and electricity to in-situ and surface mining operations. This review includes the Enhanced CANDU 6, the Advanced CANDU Reactor (ACR) and the Pebble Bed Modular Reactor (PBMR). Based on reasonable projections of available cost information, nuclear energy used for steam production is expected to be less expensive than steam produced by natural gas at current natural gas prices and under $7/MMBtu (CAD). For electricity production, nuclear becomes competitive with natural gas plants at natural gas prices of $10–13/MMBtu (CAD). Costs of constructing nuclear plants in Alberta are affected by higher local labor costs, which this paper took into account in making these estimates. Although more definitive analysis of construction costs and project economics will be required to confirm these findings, there appears to be sufficient merit in the potential economics to support further study. A single 500MWth PBMR reactor is able to supply high-pressure steam for a 40,000 to 60,000 bpd Steam Assisted Gravity Drainage (SAGD) plant, whereas the CANDU and ACR reactors are unable to produce sufficient steam pressures to be practical in that application. The CANDU, ACR and PBMR reactors have potential for supplying heat and electricity for surface mining operations. The primary environmental benefit of nuclear energy in this application is to reduce CO2 emissions by up to 3.1 million metric tons per year for each 100,000 barrel per day (bpd) bitumen production SAGD facility, or 2.0 million metric tons per year for the replacement of 700MWe of grid electricity with a nuclear power plant. Should carbon emissions be priced, the economic advantages of nuclear energy would be dramatically improved such that with a $50/ton CO2e at the releases expected for typical projects using natural gas, breakeven gas prices for nuclear drop to less than $3.50/MMBtu, well below the current natural gas price of $10/MMBtu for SADG steam production.

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.