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Approximately 60 per cent of Alberta's oil sands production is non-upgraded bitumen which, after being mixed with a diluting agent (diluent) to allow transport, is exported. A popular view within Alberta -- and particularly among Albertan politicians -- is that a much larger share of oil sands bitumen should be upgraded in the province. However, without public subsidies or government underwriting, it is uneconomic to build and operate new facilities in Alberta to fully upgrade the bitumen into synthetic crude oil. But there are new partial upgrading technologies being developed that, subject to successful testing at a larger (commercial) pilot scale, can prove to be not only economic in Alberta, but also generate large social and economic benefits for the province. The advantages include a much smaller capital investment, a significant increase in the value of the product and market for the product and, even more importantly, a dramatic reduction in the need for large amounts of expensive diluent to transport the product to market. Indeed, the only diluent required will be that to move the bitumen from the production site to the partial upgrader and this can be continually recycled. The market for the synthetic crude oil produced by full upgrading is only getting tougher. Any Alberta bitumen fully upgraded here would compete closely with the rapidly expanding supply of light U.S. unconventional oil. Partial upgrading does not upgrade bitumen to a light crude, but to something resembling more of a medium or heavy crude, and at a lower cost per barrel than full upgrading. Unlike in the increasingly crowded light-crude market, the Alberta Royalty Review Advisory Panel recognized that currently there are gaps in several North American refineries that could be filled by this partially upgraded Alberta oil. A partial upgrader serving that less-competitive market not only appears to hold the potential for investors to make attractive returns in the long term, it would also provide important benefits to Alberta from a social perspective. Since partially upgraded crude can be shipped via pipeline without diluent (as bitumen requires), producing it in Alberta would free up pipeline capacity otherwise tied up by current volumes of diluted bitumen or dilbit (diluent typically represents about one-third of each barrel of dilbit). It also reduces the cost to shippers of paying tolls for diluent exported in the dilbit and recovering diluent at the U.S. pipeline terminal, where it is less valuable than if it were recovered in Alberta at the partial upgrader. The value of each barrel produced would also be higher, benefitting oil sands producers. Partial upgrading also seems to promise a lower emissions-intensity profile compared to other bitumen-processing technologies. Based on the model of a single 100,000-barrel-a-day partial upgrader, the value uplift could be $10 to $15 per bitumen barrel. Meanwhile, there could be an average annual increase to Alberta's GDP of $505 million, and as many as 179,000 person-years of employment created (assuming a 40.5-year operating period). The increase in taxable earnings would increase provincial revenues by an average of $60 million a year, not including additional federal tax revenues. If successful, there would be many such partial upgraders with corresponding multiplication of these benefits. But there remains the critical task of proving partial upgrading technology at a higher scale than current testing. This might also depend on the province helping sustain investors through the "death-valley" between successful research and initial testing and demonstration of full commercial viability. The province has stepped into help technologies cross that "death valley" before. The promise of partial upgrading may well justify, as manager and steward of Alberta's resources, helping bridge that valley again. [ABSTRACT FROM AUTHOR]

Within BlackGold Lease located in northern Alberta, the Lower Cretaceous McMurray Formation contains the most prolific bitumen reservoirs deposited in fluvial to tidally-influenced estuarine environments. Based on core descriptions and wire-line log evaluation, this study reveals six lithofacies: cross-stratified sandstone and mudstone-clast breccia (Lf1), sandstone-dominated IHS (Lf2), mudstone-dominated IHS (Lf3), thinly interbedded sandstone and mudstone (Lf4), laminated mudstone (Lf5), and clean sandstone with interbedded mudstone (Lf6). To understand the evolution of depositional environments vertical and lateral associations of lithofacies are examined using well cross-sections and lithofacies slice maps. During overall rise in relative sea level, the McMurray Formation evolved through three stages of deposition: early stage represents fluvial channels with minor tidal influence, middle stage represents tidally-influenced estuary with well-developed meandering channels, and late stage represents a drowning of tidally-influenced estuary. The potential bitumen reservoirs are fluvial channel sandstones in the early stage and lower point-bar deposits in the middle stage. The fluvial channel sandstones are well stacked and correlatable between wells, forming sheet-like sandstone bodies that align in a SW-NE direction parallel to the inferred orientation of major channel systems. The lower point-bar deposits consist mainly of base-of-channel and sandstone-dominated IHS deposits. The direction of point-bar migration, which is crucial in horizontal well design for bitumen production, is inferred from lithofacies slice maps. The lateral changes in lithofacies from base-of-channel to abandoned channel-fills through IHS deposits, shown in lithofacies slice maps, probably indicate that the point bar once migrated toward abandoned channel-fills. Based on this lateral lithofacies trend, the dip direction of some point-bar deposits are approximately estimated to be southwestward or northwestward, which is oblique or perpendicular to the major channel orientation. [ABSTRACT FROM AUTHOR]