The benefits of partial upgrading: Challenging the size of the prize

The benefits of partial upgrading: Challenging the size of the prize

Last week, the Alberta government announced $1 billion in funding for the construction of up to five partial upgrading facilities. The plan is in response to recommendations made by the Energy Diversification Advisory Committee, tasked with finding ways to generate more revenues from Alberta's energy sector.

Most of Alberta's crude oil production is in the form of bitumen, a heavy sour crude diluted with generous volumes of condensate and shipped mostly to US refineries. This diluted bitumen trades at a significant discount to light sweet crude, causing much internal distress to both the provincial government and Alberta's producers, who view this differential as a loss of revenue.


Production of heavy oil averaged only 500,000 bbl/day during the big oil boom of 2007/2008, representing about one-third of Alberta's output. Over the next decade, that number will edge closer to 2 million bbl/day, accounting for over 60% of Alberta's production. 

Although the North American light/sweet benchmark West Texas Intermediate (WTI) topped US$60/bbl this year, the discount for Canada's heavy crude sits at over $25, theoretically representing $50 million a day in lost revenues.


By now, most Albertans have figured out that rapidly expanding oil production coupled with limited pipeline capacity has created a logistical nightmare as producers look for alternative ways to get their oil to market. 

Since Alberta's refineries are already at capacity, most of Alberta's crude is destined for export, mostly headed for the US Midwest and Gulf Coast. That all translates into higher pipeline tolls, added storage requirements and more dependancy on costly crude-by-rail. Since Alberta's crude must compete with other global sources, producers are therefore forced to take a significant haircut to get their oil to Chicago or Houston, where most of the customers are located.



The advisory committee thinks converting bitumen into a heavy or medium density crude is the answer. Bitumen has a density of about 950 kg/m³, which translates into an API density of about 8°, making it too thick and viscous to be pumped through a pipeline. A sizeable volume of diluent, typically in the order of 30% by volume, is added to raise the API density above 19°, allowing the diluted bitumen to be pipelined to market.

Once received at the refinery, the diluent is removed and returned back to northern Alberta. If producers could find a way to eliminate the need for diluent, that would free up as much as 600,000 bbl/day of capacity on Canada's pipeline export network, the volume equivalent of either the Keystone or Trans Mountain Expansion lines.



Although no one disputes the benefits of reducing diluent requirements, some of the other benefits being claimed are more difficult to quantify:

1. Lower GHG emissions

Most partial upgrading technologies rely on the removal of asphaltenes, the complex hydrocarbon molecules contained within the bottom of the barrel that make bitumen so heavy and hard to process. Removing these asphaltenes produce a crude that's slightly less heavy and less carbon-intensive to process.

However, from a well-to-wheels standpoint (from the production facility to final combustion), those savings look to be minimal at best.

Partial upgraders require steam, power and hydrogen, which all generate GHG emissions. From the producer's point of view, this comes at an added cost, soon to be priced at $50 per tonne of carbon. 

The refinery in Houston or Chicago now buys a heavy crude that's slightly easier to process and has a slightly lower carbon intensity. But Houston and Chicago do not have a price on carbon, making carbon intensity irrelevant to the buyer.

2. Higher netbacks

The jury is still out on this one. Although every technology provider claims higher netbacks, digging into the numbers makes the math not so obvious.

Building, running and maintaining a partial upgrader costs millions, if not billions. That all adds to the cost of production. As previously noted, most partial upgrading technologies rely on the removal of asphaltenes, typically reducing yields by about 10%. That translates into 10% fewer barrels sold.

So where are the cost savings? Intuitively, not having to buy expensive diluent should translate into major savings. But it's not that simple.

Diluent used in the oil sands is typically natural gas condensate, which sells at par, or even at a premium, to WTI. The selling price of Western Canadian Select (WCS), Alberta's main diluted bitumen export, includes that valuable diluent, typically 30% by volume. Strip out the diluent, and the price of the bitumen itself is much lower. 

The savings, therefore, are not in having to buy and sell diluent, but rather in the diluent transport costs. And that's only a few dollars saved per barrel.

3. Producing a more marketable heavy oil

Remove asphaltenes from the bitumen also removes a good proportion of the sulphur and heavy metals. Theoretically, partial upgrading has the potential to produce higher quality heavy oil that's easier to process, increasing the number of refineries that can purchase the crude.

True, but perhaps immaterial.

Unless the producer has a dedicated pipeline or relies on crude-by-rail, partially upgraded bitumen will travel on the same network as diluted bitumen. Any uplift on the selling price of this "higher-quality" heavy crude has yet to be confirmed.

There are certainly no lack of buyers for Alberta's diluted bitumen. As the world's refineries become more and more complex, their capacity to handle the bottom of the barrel is no longer an issue.

Finding a customer for Alberta's oil is not the problem. The problem is getting the oil to the customer.

4. Freeing up pipeline capacity

Theoretically, eliminating the need for diluent would free up more than 500,000 bbl/day of pipeline capacity. More pipeline capacity would reduce the need for storage in Alberta and lower transportation costs. That should translate into a smaller discount for Alberta's heavy oil.

But one or two partial upgraders aren't enough to move the needle, unless those facilities are very large. A 100,000 bbl/day partial upgrader would take up to 30,000 bbl/day of diluent out of Canada's export pipelines. One producer needs to swallow all the costs, but the benefit in terms of price uplift would be negligible, unless many producers also take the plunge.

Put another way, if you want to reduce congestion on a highway, you need to remove a lot of cars to make a difference. The alternative, of course, would be to build a whole new highway.

5. Significantly cheaper than a full upgrader

Latest estimates peg a 100,000 bbl/day partial upgrader at about $3 billion, versus well north of $10 billion for a full upgrader. True, but full upgrading isn't the alternative. The alternative is no upgrader at all, and it doesn't get much cheaper than that.


Getting any new process off the ground requires lots of time, patience and in many cases, government intervention.

Partial upgrading is an interesting technology that has the potential to reshape the oil sands industry. But it comes at a significant cost and isn't a viable alternative to building more pipelines. At least not in the short term.

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