Propelled by the boom in oil sands and tight oil production, condensates, an ultra-light oil, are emerging as an ever more important element of the energy industry. The increasing prevalence of condensates may be a point of concern, however, as they are at least partially responsible for the increasing volatility of North American crude, particularly as it travels by rail. Additionally, they represent a significant cost to oil sands producers that require condensates to dilute bitumen for pipeline transport.
Hydrocarbons are measured on a carbon number scale to reflect the number of carbon atoms contained in each molecule, with lower numbers signifying lighter, gassier, and more volatile carbon molecules. Condensates typically fall between C4 and C12—raw bitumen, on the other hand, has a carbon number of C35 or higher.
Oil sourced from recent shale plays in the United States (often referred to as “light, tight crude”) is naturally composed of more of these lighter carbon molecules. This has created problems for oil transport, as crude from plays like North Dakota’s Bakken shale has turned out to be more explosive than originally anticipated. While accidents involving traditional crude resulted in environmentally damaging oil spills and fire, this ultra-light crude can detonate like a bomb. This was experienced first hand last summer when a train carrying Bakken crude derailed in Lac-Mégantic, Quebec, decimating the town’s core and leaving 47 dead.
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Meanwhile, extra heavy crude like Albertan bitumen is too thick to flow through pipelines and must be diluted, with condensates serving as the diluent of choice for most producers. Bitumen is typically mixed with approximately 30 percent condensate before being shipped by pipeline. However, condensates tend to sell at a premium to the West Texas Intermediate benchmark, so this practice is expensive and adding condensates to bitumen cuts into producer profit margins. As oil is moved from pipeline to railcar, the diluent is no longer required and only serves to increase volume, which reduces the efficacy of bitumen rail transport. Oil companies are forced to pay a double cost for condensates—first purchasing the diluent, and then paying the opportunity cost of lost bitumen volume transported by rail.
To address the latter problem, some companies are attempting to extract the diluent before transferring the mixture from pipeline to railcar. Calgary-based Cenovus Energy Inc. is investigating the viability of a so-called diluent recovery unit to do just that. “We are looking at that and how that enhances economics, including the economics of unit train capacity,” said CEO Brian Ferguson. MEG Energy Corp. is also pursuing this option, spending $75 million to construct a diluent recovery facility next to a loading facility in Bruderheim, Alberta.
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Shipping raw bitumen by rail without the presence of a diluent cuts cost significantly. According to the energy consultancy IHS CERA, using this method to transport bitumen between Alberta and the U.S. Gulf Coast refining hub shrinks the cost differential to $6 per barrel when compared to pipeline transport.
The Canadian Association of Petroleum Producers forecasts that oil sands production will increase to 4.45 million barrels per day by 2025 from 1.8 million barrels per day in 2012. Absent diluent recovery technology, this means that condensate as diluent demand will more than double over the next decade, putting further upward pressure on prices and increasing transport costs for oil sands producers.
Expensive and explosive, these condensates are proving a thorn in the side of producers, transporters, and regulators alike. However, as both oil sands and tight oil production are likely to continue rising, North America is going to see more and more of this ultra-light oil transiting the continent. Government must recognize both the peril and potential these hydrocarbons represent and act accordingly.
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By Rory Johnston of Oilprice.com
1. There is a premium above WTI to buy condensate on the Gulf Coast.
2. It has to be pipelined from the Gulf Coast to northern Alberta.
3. Thirty percent more pipeline capacity and costs are required to export dilbit which is 30 percent condensate/70 percent raw bitumen.
4. There is a loss selling the condensate as dilbit which sells at a discount to WTI.
Total cost per barrel raw bitumen to use condensate approaches $25/barrel bitumen.
That, plus jobs, profits and taxes makes upgrading, refining and adding even more value through petro-chemicals is why doing all of that is economic to do in Canada.
Don't believe oil companies like ExxonMobilwho say it isn't profitable to do that in Canada.
They want all the benefits of cheap, raw bitumen on the Gulf Coast for export as high-value diesel from duty-free and tax-free Free-Trade Zones to Latin America.