Western Canadian heavy crude production from tar sands (bitumen) is expected to increase from about 1.7 MMbd/ in 2011 to 2.9 MMbd/d in 2017. Forty percent of that production is mixed with diluent (mostly natural gasoline or condensate) and shipped to the US market by pipeline. As tar sands production increases so does Canadian demand for diluent. That demand already outstrips local production - meaning Canada needs to import increasing volumes of diluent. Today we look at the potential sources of Canadian diluent supplies.
We have previously discussed the market for heavy sour Canadian crude. These crudes are most suitable to displace similar grades from Mexico and Venezuela that are currently refined on the US Gulf Coast (see Production Stampede – Where Will Canadian Oil Production Go?). That means transporting the crudes 2000 miles or more from Alberta to the Gulf Coast. The most efficient way to make that journey is by pipeline.
Before Canadian heavy crude production is transported by pipeline it first needs to be transformed - by upgrading or mixing with diluent. That is because it comes out of the ground as treacle like bitumen that does not flow. Upgrading involves partially refining the heavy bitumen to produce synthetic crudes. These synthetic crudes are typically low in sulfur and have an API gravity of about 34-36 e.g. Canadian Light Synthetic crude (called synbit). Synthetic crudes can be shipped by pipeline. Alternatively (and usually less expensively) tar sands crude can be blended with diluent to reduce its viscosity so that it will flow in a pipeline. We previously described this process by which Canadian heavy crude producers blend bitumen with diluent to make “dilbit” crude (see It’s a Bitumen Oil – Does it Go Too Far?). An example is Western Canadian Select crude (WCS). Dilbit crudes typically have high sulfur (3 percent plus) and a low API gravity of about 20. The chart below shows Canadian tar sands production from 2005 with a forecast out to 2017. Production in 2011 was 1.7 MMb/d and that number will increase to 2.9 MMb/d in 2017. The chart shows both upgraded and non-upgraded production volumes. The upgraded crude accounted for about 57 percent of the volume in 2011 with about 40 percent requiring diluent for pipeline transportation. Our focus in this blog is on the diluent blended crude.
Source: Bentek and Canadian Energy Research Institute (Click to Enlarge)
The amount of diluent needed to blend bitumen crude to meet pipeline specifications varies with the type of diluent used and the viscosity of the tar sands bitumen. The general rule of thumb is that a 70:30 mixture of bitumen and diluent is necessary. We will cover the different varieties of diluent used in a moment. First looking back to the chart we can see that the non-upgraded tar sands volume is increasing over time. In 2011 the amount of tar sands mixed with diluent was 40 percent of production or 680 Mb/d but by 2017 the amount of non-upgraded tar sands will increase to 55 percent of production or 1.6 MMb/d. At the rule of thumb rate of 30 percent the volume of diluent required in 2011 was about 200 Mb/d increasing to 480 Mb/d in 2017. Canada supplied about 148 Mb/d of its own diluent in 2011. That number is expected to decline slightly by 2017 to 138 Mb/d. That leaves a net Canadian diluent import demand of 480 – 138 or 342 Mb/d in 2017.
Where will that diluent come from? First lets look at the choices for diluent blending. The diluent most favored by Canadian producers is one that requires the least volume to blend bitumen to pipeline specification, has consistent quality specifications, ,and adds the most value for refiners who process dilbit. The product that performs best against these criteria is natural gasoline. Natural gasoline is a natural gas liquid (NGL) that is primarily composed of C5’s, or normal pentanes, a product which has ~5 carbon molecules for each hydrogen molecule (C5) and is produced by gas processing plants (see It’s a Natural Fact). A “second best” alternative diluent is condensate – a product that has various definitions, specifications and origins (see Fifty Shades of Condensate – Which One Did You Mean?).
Because condensate is heavier than natural gasoline a greater volume of condensate is required to blend dilbit to pipeline specification. Condensates are less attractive than natural gasoline to refiners since their quality can be variable whereas natural gasoline has long been a traditional part of the gasoline blending pool. Being “attractive” to refiners is important because whatever diluent is used to make dilbit crude ends up in refineries and if it is not useful then its value will be discounted. Canadian producers can also use very light crudes as diluent (e.g. synthetic crude or Bakken light sweet) but these are heavier than C5 or condensate and require larger blend volumes. A much lighter alternative diluent is butane (API range 75 – 115) but that has a very high Reid Vapor Pressure that exceeds crude pipeline specifications (see Wasted Away in Butane Blendingville) so very little can be added to dilbit.
Generally speaking, Canadian producers prefer natural gasoline as bitumen diluent. In 2012 according to EIA one third of US natural gasoline (pentanes plus) or 115 Mb/d was exported – mostly to Canada for use as diluent. US natural gasoline production is growing along with all of the NGLs produced from wet gas shale. US production of natural gasoline is expected to increase from 315 Mb/d in 2012 to 425 Mb/d in 2017 (Bentek). If the percentage stays at one-third then exports to Canada would increase from 115 to 140 Mb/d in 2017. Recall from our earlier calculation that Canadian producers will need to import ~340 Mb/d of diluent in 2017. Assuming 140 Mb/d of natural gasoline exports from the US, that leaves 200 Mb/d that has to come from lease condensate.
As Canadian luck would have it, supplies of US lease condensate are increasing rapidly in the tight oil shale basins. We have written several blogs on expanding US lease condensate production – most recently on the Eagle Ford basin – where condensate is estimated to make up anywhere from 30 to 70 percent of crude production (see Don’t Let Your Crude Oils Grow Up to be Condensates). Because condensates are hard to define, field production estimates vary considerably. However US Energy Information Administration (EIA) data for 2010 implies that condensate represented about 11 percent of total crude production. We estimate that number will increase to 14 percent by the end of this year (2013) meaning over 1.2 MMb/d of condensate production. That is far more than enough to meet the import demand for diluent in Canada.
The expanding Canadian diluent market is nothing but good news for US lease condensate producers. As we explained earlier condensate is not popular with refineries because of quality concerns. It is also the case that most US refineries are not configured to handle very light feedstocks like condensate so prices are often heavily discounted (see What Should be Done With Condensates). US producers are not allowed to export lease condensate anywhere except Canada without processing it first (see Fifty Shades Lighter – The Condensate Export Problem). As rising volumes of condensate from the South Texas Eagle Ford shale flow to Houston by pipeline and by barge from Corpus Christi to St. James, LA the refining market is rapidly becoming oversupplied. As a result the demand for diluent in Canada is a godsend for producers – at least until US refiners figure out how to handle condensate more profitably.
In the second episode in this two part series we will look at projected demand for diluent in Canada out to 2020 as well as how the necessary imports to meet that demand will get to market. Those supplies are currently heavily dependent on pipeline capacity from the US and the West Coast of Canada. Not all of that capacity will get built. We will also review the likely impact on diluent demand if Canadian producers decide to ship more of their crude to market by heated rail car – a process that requires far less diluent.
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Comments
Question
Great article as usual, but it has brought up one question that I've never been able to figure out.
Your explanation for why Natural gasoline is preferred to condensate makes perfect sense to me. (Assuming the dilluent is produced in Canada) It is when you include the additional option of blending heavy oil with light crudes that I become confused and wonder if you can elaborate further on what drives the economics of it.
My understanding is that pipeline cost between Western Canada and the Gulf Coast run 15-20/B. Now given that both the light sweet and the heavy crude need to make the trip anyway, I fail to understand why blending them isn't the most economical choice even after considering that less heavy crude could be blended in any individual batch as a result.
To me when I think of sending Natural gasoline and/or condensates from the Gulf to Canada, with the attended cost, only to pay again to send it back to the Gulf where it isn't needed doesn't make a lot of sense on the surface.
What am I missing?
B
Good question.
Good question.
There has been a lot of discussion of moving light sweet Bakken crude up to Western Canada to use as a blend component but none of the scemes have come to fruition so far. You would have to figure a shipping route for the oil (rail is the obvious choice). Perhaps Bakken producers feel that once they have their crude on rail then the best market is the East or West coast (or the Gulf at the moment) rather than sending it to Edmonton?
Technically - it is chemistry that determines what mixture of a light crude is needed to blend with bitumen - the lighter the crude - the less volume needed.
Sandy