A barrel of oil sands bitumen has value only once a refinery can process it, and only a limited number of refineries are equipped to do that. Bitumen is dense, viscous, and rich in heavy molecules called asphaltenes, so it needs significant processing before it can become the fuels and products of the modern world.

In the first article in this series, Not all crude oil is created equal, we looked at how crude oils are classified and why bitumen sits at the heaviest end of the range. Here, we look at what the industry does about it: the established technologies used to make bitumen refinable and – when conducted upstream – pipeline-ready, and the trade-offs in yield, energy, and cost that each one carries. Those trade-offs are why interest continues to grow in partial upgrading—approaches that aim primarily for transport behaviour improvement alongside meaningful quality improvement, without the full cost of a conventional upgrader.

Dilution or upgrading: Two paths to the refinery

Blending in lighter hydrocarbons solves the flow problem, but takes up pipeline capacity and limits customers to heavy refineries in the process.

Pipelines are generally the most economical and practical way to move crude oil over land, provided the oil is pumpable. In practice, that means it needs to be a low-viscosity liquid at ambient conditions. Bitumen is not, largely because it contains a high concentration of asphaltenes: large, complex, high-molecular-weight, polar molecules that make the oil thick and dense.

The most common workaround is dilution. Bitumen is blended with light hydrocarbons, such as natural gas condensate, to produce diluted bitumen, or dilbit. Dilbit typically contains about 30 percent diluent. That allows the bitumen to flow, but it also means about 30 percent of the pipeline's capacity is taken up by diluent rather than bitumen, which has real economic consequences and exacerbates bottlenecks in crude export. As well, the continued presence of asphaltenes (and vacuum residuum more broadly) limits the refineries that can process dilbit to heavy “deep conversion” refineries that have the ability to remove or convert the heavy fraction of the diluted bitumen.

The alternative is upgrading. Upgrading converts the heaviest fractions of the crude, including the asphaltenes, into lighter compounds (or removes them outright), reduces sulfur and other impurities, and increases the ratio of hydrogen to carbon in the oil. The result is synthetic crude oil (SCO): a light, sweet crude that is compatible with pipelines on its own and can be processed in medium or light refineries.

Cleaning bitumen at the source

How paraffinic froth treatment removes water and solids, and begins to lighten the bitumen along the way.

Depending on how bitumen is extracted, some initial pre-upgrading can occur during extraction itself. Mined oil sands bitumen arrives mixed with water, sand, and other mineral material. One way to separate the bitumen from these is paraffinic froth treatment (PFT).

In PFT, the contaminated bitumen is thoroughly mixed with a paraffinic solvent and sent to a series of settlers. There, water, sand, and other contaminants (known collectively as tailings) settle out by gravity and are sent to tailings ponds. The solvent is then recovered from the cleaned bitumen.

The main purpose of PFT is to remove water and solids, but it has a useful side effect. Asphaltenes dissolve poorly in paraffinic solvents, so a portion of them are lost from the bitumen, lowering its viscosity and density. There is a limit to how much asphaltene can be rejected. Rejection of large proportions of the asphaltene requires large ratios of solvent (or lighter solvents) adding to operating and capital costs. As well, removing too many asphaltenes reduces the amount of product recovered, which can also impact overall economics. Further, regulatory limits on the amount of bitumen that can be lost to the tailings create an additional limit on the extent to which PFT can be used for asphaltene rejection. From a practical standpoint, PFT typically aims for 40 to 50 percent asphaltene rejection. Bitumen treated this way still needs dilution or further upgrading before it can travel by pipeline.

Primary upgrading: Raising the hydrogen-to-carbon ratio

Every major upgrading technology answers the same question: remove carbon, or add hydrogen?

Primary upgrading usually starts by distilling off any diluent, along with the lightest components of the bitumen itself. What remains is the distillation residue: the heavy fraction left behind once the lighter molecules have boiled off. This residue is then converted into smaller, lighter compounds. Afterward, the fractions can be recombined to produce SCO, or sent individually for further refinery processing. All heavy-crude refineries that process bitumen have some degree of primary upgrading.

The goal throughout is to increase the hydrogen-to-carbon ratio. Lighter, more valuable hydrocarbons carry more hydrogen for every carbon atom; heavy molecules such as asphaltenes carry less. There are two ways to shift that balance: reject carbon, or add hydrogen. Today's main bitumen upgrading technologies each follow one of these two pathways.

Rejecting carbon: Coking and solvent deasphalting

Two approaches that improve the oil by removing its heaviest portion.

Coking

Coking is the main commercial technology for rejecting carbon. A coker applies high temperatures to the distillation residue, thermally cracking its large molecules into smaller ones and leaving behind petroleum coke (petcoke), a carbon-rich solid often used as fuel in industrial boilers. Coking typically produces up to about 20 percent coke by mass of the bitumen feed, plus about 5 percent lost to gases, with a matching reduction in the amount of upgraded oil recovered.

Because coking runs at severe, high-temperature conditions, it is energy intensive. Its liquid product also contains a significant share of unsaturated (olefinic) molecules, which have carbon–carbon double bonds that make them less stable. These must be saturated in a hydrotreater before the product is recombined with the lighter fractions and shipped as SCO. Hydrotreating, covered below, also removes sulfur and other impurities, and is often referred to as secondary upgrading.

Solvent deasphalting

A second carbon-rejection approach is solvent deasphalting (SDA). The distillation residue is mixed with a short-chain paraffinic solvent, such as pentane, chosen to dissolve the more paraffinic (and typically lighter) compounds while leaving asphaltenes and other more polar molecules behind. In effect, it is a more thorough version of the asphaltene rejection that happens during PFT.

The resulting stream, deasphalted oil (DAO), contains far less of the heavy, flow-restricting asphaltenes. Yields are the trade-off: DAO recovery is generally around 85 to 95 percent, since a significant portion of the oil is rejected to achieve a clean, asphaltene-free product. Even then, typical DAO still contains around 1 to 3 percent asphaltene, limiting its suitability to light or medium refineries. For this reason, SDA is rarely used as a primary upgrading method, and when it is, it is typically paired with another upgrading technology.

Adding hydrogen: Hydrocracking and hydrotreating

Higher yields and a more stable product, at a higher cost.

Hydrocracking

At the other end of the spectrum are hydrogen-addition technologies, led by hydrocracking. In a hydrocracker, the heavy feed reacts with hydrogen gas at high temperature and pressure in the presence of a metal-on-zeolite catalyst (metal particles supported on a porous mineral framework that accelerates the reaction). Large hydrocarbons are cracked into smaller molecules, and the hydrogen-rich environment produces a largely saturated, stable product. Sulfur, nitrogen, and other impurities are removed at the same time, so the product leaves the hydrocracker already partially hydrotreated.

Because hydrocracking does not reject carbon, yields are much higher than with coking or SDA, often greater than 95 percent. The trade-off is cost. Hydrocracking is more capital intensive than the carbon-rejection technologies, and considerably more expensive to operate, driven in part by the high hydrogen pressures it requires.

Secondary upgrading (hydrotreating)

Hydrotreating is generally considered secondary upgrading. The feed reacts with hydrogen gas over a catalyst, converting sulfur and nitrogen impurities into hydrogen sulfide and ammonia, respectively, which are removed as gases. Olefinic molecules are saturated, improving the stability and pipeline compatibility of the oil.

Hydrotreating operates at lower severity than hydrocracking: carbon–carbon bonds remain intact. It is a well-established technique used across many petroleum streams, not only bitumen and heavy oil, and is common to light, medium, and heavy refineries. Like hydrocracking, it depends on a supply of hydrogen gas, which often means upgrading facilities need to be located near other refining or upgrading infrastructure.

Comparing the main approaches

Where each technology gains, and what it gives up.

The case for partial upgrading

Why the trade-offs of conventional upgrading leave room for new approaches.

Bitumen's density, viscosity, and sulfur content make it difficult to transport and challenging for refiners. Synthetic crude oil, by contrast, is light, sweet, and far more readily refined. Upgrading unlocks that refinery value, but producers must weigh the increased upstream value capture and improved transportability from SCO against the costs of upgrading at remote sites: yield loss, energy use, infrastructure capital, and hydrogen generation.

That balance creates a clear opening for upstream partial upgrading: approaches that can ease the logistical and economic burdens of transporting bitumen and could deliver meaningful quality improvement without the capital and process intensity of full upgrading. More broadly, it points to the value of technologies able to achieve substantial molecular transformation under practical operating conditions.

This is the challenge we are applying our Hydrochemolytic™ Technology (HCT) to. Our bitumen work is at the technology demonstration (bench scale) stage, where we are evaluating how HCT's moderate operating conditions, selective conversion, and efficient use of water as a reaction medium can convert the heaviest molecules in bitumen into lighter oil that is easier to transport and more valuable to process, with the potential to reduce reliance on diluent and free up pipeline capacity for the bitumen itself.

Bitumen will always start out heavy. The open question is what it costs to make it move and turn it into the fuels of the modern world—and that is where we see room for new chemistry.

Learn more about our bitumen upgrading work

Sources:
Canada Energy Regulator, Market Snapshot: A tour of Canada's oil sands upgraders (2022)
Oil Sands Magazine, Anatomy of a bitumen upgrader
Jacobs Consultancy for Alberta Innovates, Bitumen Partial Upgrading 2018 Whitepaper