The magnitude of Canada's oil sands reserves, their rapidly expanding and energy intensive production, combined with existing and upcoming greenhouse gas (GHG) emissions regulations motivate an evaluation of oil sands-derived fuel production from a life cycle perspective. Thirteen studies of GHG emissions associated with oil 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 to 176 kgCO 2 eq/bbl SCO, respectively (or 9.2-26.5 and 16.2-28.7 gCO 2 eq MJ −1 SCO, respectively), compared to 27-58 kgCO 2 eq/bbl (4.5-9.6 gCO 2 eq MJ −1 ) of crude for conventional oil production. The difference in emissions intensity between SCO and conventional crude production is primarily due to higher energy requirements for extracting bitumen and upgrading it into SCO. On a 'well-to-wheel' basis, GHG emissions associated with producing reformulated gasoline from oil sands with current SM&Up, IS&Up, and in situ (without upgrading) technologies are 260-320, 320-350, and 270-340 gCO 2 eq km −1 , respectively, compared to 250-280 gCO 2 eq km −1 for production from conventional oil. Some variation between studies is expected due to differences in methods, technologies studied, and operating choices. However, the magnitude of the differences presented suggests that a consensus on the characterization of life 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 government decision making.

New data enable targeted policy to lessen GHG emissions

Natural gas based hydrogen production with carbon capture and storage is referred to as blue hydrogen.

Life cycle greenhouse gas (GHG) emissions associated with two major recovery and extraction processes currently utilized in Alberta's oil sands, surface mining and in situ, are quantified. Process modules are developed and integrated into a life cycle model-GHOST (GreenHouse gas emissions of current Oil Sands Technologies) developed in prior work. Recovery and extraction of bitumen through surface mining and in situ processes result in 3-9 and 9-16 g CO(2)eq/MJ bitumen, respectively; upgrading emissions are an additional 6-17 g CO(2)eq/MJ synthetic crude oil (SCO) (all results are on a HHV basis). Although a high degree of variability exists in well-to-wheel emissions due to differences in technologies employed, operating conditions, and product characteristics, the surface mining dilbit and the in situ SCO pathways have the lowest and highest emissions, 88 and 120 g CO(2)eq/MJ reformulated gasoline. Through the use of improved data obtained from operating oil sands projects, we present ranges of emissions that overlap with emissions in literature for conventional crude oil. An increased focus is recommended in policy discussions on understanding interproject variability of emissions of both oil sands and conventional crudes, as this has not been adequately represented in previous studies.

A life cycle-based model, GHOST (GreenHouse gas emissions of current Oil Sands Technologies), which quantifies emissions associated with production of diluted bitumen and synthetic crude oil (SCO) is developed. GHOST has the potential to analyze a large set of process configurations, is based on confidential oil sands project operating data, and reports ranges of resulting emissions, improvements over prior studies, which primarily included a limited set of indirect activities, utilized theoretical design data, and reported point estimates. GHOST is demonstrated through application to a major oil sands process, steam-assisted gravity drainage (SAGD). The variability in potential performance of SAGD technologies results in wide ranges of "well-to-refinery entrance gate" emissions (comprising direct and indirect emissions): 18-41 g CO(2)eq/MJ SCO, 9-18 g CO(2)eq/MJ dilbit, and 13-24 g CO(2)eq/MJ synbit. The primary contributor to SAGD's emissions is the combustion of natural gas to produce process steam, making a project's steam-to-oil ratio the most critical parameter in determining GHG performance. The demonstration (a) illustrates that a broad range of technology options, operating conditions, and resulting emissions exist among current oil sands operations, even when considering a single extraction technology, and (b) provides guidance about the feasibility of lowering SAGD project emissions.

A petroleum refinery model, Petroleum Refinery Life-cycle Inventory Model (PRELIM), which quantifies energy use and greenhouse gas (GHG) emissions with the detail and transparency sufficient to inform policy analysis is developed. PRELIM improves on prior models by representing a more comprehensive range of crude oil quality and refinery configuration, using publicly available information, and supported by refinery operating data and experts' input. The potential use of PRELIM is demonstrated through a scenario analysis to explore the implications of processing crudes of different qualities, with a focus on oil sands products, in different refinery configurations. The variability in GHG emissions estimates resulting from all cases considered in the model application shows differences of up to 14 g CO₂eq/MJ of crude, or up to 11 g CO₂eq/MJ of gasoline and 19 g CO₂eq/MJ of diesel (the margin of deviation in the emissions estimates is roughly 10%). This variability is comparable to the magnitude of upstream emissions and therefore has implications for both policy and mitigation of GHG emissions.

Life cycle assessment (LCA) analysts are increasingly being asked to conduct life cycle-based systems level analysis at the earliest stages of technology development. While early assessments provide the greatest opportunity to influence design and ultimately environmental performance, it is the stage with the least available data, greatest uncertainty, and a paucity of analytic tools for addressing these challenges. While the fundamental approach to conducting an LCA of emerging technologies is akin to that of LCA of existing technologies, emerging technologies pose additional challenges. In this paper, we present a broad set of market and technology characteristics that typically influence an LCA of emerging technologies and identify questions that researchers must address to account for the most important aspects of the systems they are studying. The paper presents: (a) guidance to identify the specific technology characteristics and dynamic market context that are most relevant and unique to a particular study, (b) an overview of the challenges faced by early stage assessments that are unique because of these conditions, (c) questions that researchers should ask themselves for such a study to be conducted, and (d) illustrative examples from the transportation sector to demonstrate the factors to consider when conducting LCAs of emerging technologies. The paper is intended to be used as an organizing platform to synthesize existing methods, procedures and insights and guide researchers, analysts and technology developer to better recognize key study design elements and to manage expectations of study outcomes. K E Y W O R D Searly stage technology assessment, environmental impacts, industrial ecology, life cycle assessment (LCA), research and development (R&D), unintended consequences

Direct air capture (DAC) separates carbon dioxide (CO 2 ) from ambient air either chemically or physically. As such, it could be a potential climate mitigation tool when paired with geological sequestration of CO 2 or downstream conversion to produce products with low life cycle carbon intensities. Of particular interest is the ability to pair CO 2 from DAC with electrolytic hydrogen powered by renewable electricity to synthesize liquid hydrocarbons that can be used in transportation (often referred to as "e-fuels"). This presents a pathway additional to electric and fuel cell vehicles to harness renewable electricity for use in the transportation sector and may present an attractive opportunity as costs of renewable electricity and electrolysis equipment continue to fall. We conduct a life cycle assessment (LCA) of the greenhouse gas (GHG) emissions of a DAC system paired with Fischer-Tropsch synthesis (FTS) to produce transportation fuel (i.e., diesel). This is the first LCA study of a DAC-to-fuel process based on data from an operating DAC pilot plant. We estimate the system emits 0.51 gCO 2 e per gCO 2 captured from air or 29 gCO 2 e per MJ FTS fuel combusted in the baseline scenario, in which the electricity emissions factor used in the process is relatively low. This carbon intensity (CI) is extremely sensitive to changes in the electricity emissions factor. We find that an electricity emissions factor of less than 139 g CO 2 e per kW h is required for this pathway to provide a climate benefit over conventional diesel fuel. If a low carbon source of electricity is used, this pathway can deliver transport fuels at a CI lower than conventional diesel production and several biofuel pathways. This analysis suggests that fuel synthesis facilities need to be located in regions with very low grid emissions factors, or preferentially, co-located with new-build renewable electricity.