Upgrader

Key Takeaways

• Delayed coking is the most widely used carbon rejection upgrading process in oil sands facilities, using a two-stage thermal cracking sequence in which vacuum distillation residue (the heaviest fraction of the bitumen) is heated to 480 to 510 degrees Celsius in a coker furnace and then fed to a large coke drum where thermal cracking reactions convert heavy hydrocarbons to lighter gas and liquid products plus solid petroleum coke: the cracking reactions proceed without a catalyst (hence "thermal" cracking) and break the long carbon chains of the bitumen asphaltene fraction into shorter-chain molecules (naphtha, kerosene, gas oil fractions) and solid coke; the coke drums operate in pairs alternating on an 18 to 24 hour cycle, with one drum filling while the other is being hydraulically cut and decoked; petroleum coke (petcoke) produced is a high-carbon, low-hydrogen solid with heating value similar to coal and is either used as fuel at the upgrader site (in circulating fluidized bed combustors that burn petcoke to generate steam and power), sold as fuel-grade petcoke to industrial users, or sold as anode-grade petcoke to aluminum smelters depending on its sulfur and metal content.
• Fluid catalytic cracking (FCC) and hydrocracking are the hydrogen-addition routes used in upgraders to convert bitumen-derived gas oils and vacuum gas oils into lighter products while desulfurizing and denitrogenating the product streams: hydrocracking uses high-pressure hydrogen (1,500 to 3,000 psi) and a bifunctional catalyst (zeolite acid sites for cracking plus metal sulfide sites for hydrogenation) to crack heavy molecules and simultaneously hydrogenate the cracked fragments, producing a product stream that is fully saturated, low in sulfur (below 50 ppm), and lighter than the feed; hydrocracking requires a continuous supply of high-purity hydrogen, which in oil sands upgraders is typically produced by steam methane reforming (SMR) of natural gas, making natural gas supply and price a significant operating cost variable; the CNRL Horizon upgrader uses an integrated delayed coker plus hydrocracker configuration in which the coker handles the heaviest asphaltene fraction and the hydrocracker processes the lighter gas oil fractions, achieving a synthetic crude oil product with API gravity of 35 to 37 degrees and sulfur below 0.1 percent.
• Diluent blending is an alternative to full upgrading that allows bitumen to be transported in pipelines without a capital-intensive upgrader, by blending bitumen with natural gas condensate (diluent) at a ratio of approximately 30 percent diluent to 70 percent bitumen by volume to produce a blended product called dilbit (diluted bitumen) with viscosity below the pipeline specification limit: dilbit is the transport mode used by producers who export bitumen to refineries without building their own upgrader, representing approximately 60 percent of Alberta oil sands production as of the mid-2020s; the trade-off between upgrading and dilbit transport involves the capital cost of an upgrader (typically $10,000 to $20,000 per barrel per day of capacity, implying $5 to $10 billion for a 500,000 bbl/d facility) against the lower realized price of dilbit relative to synthetic crude oil (typically $10 to $20 per barrel discount for dilbit versus SCO at the same delivery point, reflecting the cost of diluent plus the lower quality of dilbit compared to the premium SCO product).
• Sulfur recovery is a critical environmental control process integrated into all oil sands upgraders because Alberta bitumen contains 4 to 5 percent sulfur by weight, which is released as hydrogen sulfide (H2S) during the hydroprocessing and coking steps and must be captured and converted to elemental sulfur before any stack emissions can be released: the Claus process (used universally in upgraders and refineries for H2S recovery) burns one-third of the H2S feed with air to produce sulfur dioxide (SO2), then catalytically reacts the remaining two-thirds of H2S with the SO2 over alumina or titanium catalysts at progressively lower temperatures in three to four reactor stages, recovering 94 to 99 percent of the sulfur feed as liquid elemental sulfur that is sold to the fertilizer industry (as sulfuric acid feedstock for phosphate fertilizer production) or stockpiled; upgrader sulfur recovery capacity is constrained by the regulatory requirement that total SO2 emissions from the facility remain below approved limits set by the Alberta Energy Regulator, making Claus unit availability a potential production bottleneck during planned or unplanned maintenance.
• Upgrader economics and integration strategy vary significantly between operators based on their philosophy regarding capital allocation and refinery access: fully integrated producers (Suncor, CNRL, Syncrude/Suncor) own both the oil sands production assets and the upgrader, capturing the full value chain from bitumen to SCO and selling synthetic crude oil at prices close to WTI; non-integrated producers (Cenovus, MEG Energy, Imperial Oil's Cold Lake operation) produce dilbit and sell it at a discount to light crude, avoiding the $5 to $15 billion upgrader capital cost but accepting the persistent quality and transportation cost differential; upgrader economics are most favorable when light-heavy crude differentials are wide (dilbit price is very low relative to SCO, making the upgrader margin large) and least favorable when light-heavy differentials narrow (as they did in 2018 when Canadian crude differentials compressed, reducing the economic advantage of upgrading versus dilbit).