Condensates

30-second sound bite: Canadian oil sands needs condensate to ship (pipeline) bitumen (heavy oil). Those oil fields do not have adequate condensate; they will get it from the Bakken and the Eagle Ford.

30-second sound bite: I think my thoughts on the Keystone XL are very, very wrong. Maybe a stand-alone post on that if I get caught up. 

Background: what makes wet gas wet?

There is a series of articles -- three, to be exact -- on condensates appearing on the web. 

The series (linked below) is targeted for investors. Disclaimer: my blog is not an investment site. Do not make any investment decisions based on what you read here. These articles are linked because they help me understand the Bakken.

The author is a typical "newsletter" type-of-guy, but better than many, I suppose. He provides readers with lots of interesting "information" and then requires a paid subscription "for the rest of the story."

[Another "Condensate 101" course was posted in mid-January, 2013, and might be a better place to start before reading the series of stories coming up.]

The first at Oil & Gas Investments.

The second at Oil & Gas Investments.

The third, in SeekingAlpha.

The lede from the first article:

Condensate prices in Canada are soaring—now sitting some $14/barrel ABOVE WTI—making it the most valuable Canadian energy product.

It’s creating huge profits for the lucky few natural gas producers who have large condensate volumes in their production stream.Condensate is both a heavy natural gas liquid (NGL), and a super light oil, making it very versatile.

In Canada it’s used to dilute heavy oil from the oilsands, and fast increasing production there is driving condensate demand—and prices.Canadian production of condensate is flat, which is bullish in the face of oilsands growth.

Note:  he says Canadian condensates are priced at $14 above WTI. If true, I would assume pricing is similar for Bakken condensate.

From that same article:

From the Eagle Ford shale in Texas to the Bakken shale in North Dakota and up to the Montney shale in northern BC, oil and gas shales are producing major volumes of condensate.

Some data points from the second article:

In the United States, all this condensate is almost a problem. US refiners spent billions of dollars over the last decade to process more heavy oil. As a result they can’t really handle this light stuff.

In the oil sands, condensate is used as a diluent to ‘thin down’ bitumen – a thick, sludgy substance – so it will flow through pipelines. Since bitumen production is climbing steadily, condensate demand is on the rise. Supply is struggling to keep up.
Canada now uses some 275,000 barrels of condensate per day as diluent. Canadian producers churn out 165,000 barrels per day (bpd), meaning oil sands operators already rely on imports to fill a 110,000-bpd gap.

And finally, the third article, at his website, I suppose, but also in SeekingAlpha, as linked above.

Some data points:

The reason condensate is king in Canada is that oil sands producers need piles of this light oil to dilute their heavy bitumen for transport, and Canadian production can't keep up with demand.

Half of America's refineries lie along the Gulf Coast. With the ability to process 8 million barrels of crude oil every day, this industrial complex truly sets the tone for oil pricing across the country. And guess what? Gulf Coast refineries don't like condensate.

Refineries are picky beasts, each one only able to process crudes within a particular API range. The Gulf Coast army of refineries used to love light oil, but over the last 25 years the world burned through many of its high-quality deposits of light crude. That forced producers to shift towards heavier and sourer crudes. [This is why I believe my thoughts on the Keystone Xl are very, very wrong.]

The only way to feed condensate into these medium and heavy oil refineries is to mix the light oil with a heavier crude to produce a mid-weight blend. But even that is not ideal, because it turns out a mixture of heavy oil and condensate does not produce the same products as a straight crude of similar weight.

Canada needs condensate. US producers are flooded with the stuff and want to sell it to Canadian oil sands operators. The challenge is moving it.

The only pipeline currently moving condensate from the US into Canada is Enbridge's Southern Lights line, which runs from Illinois to Edmonton. It can move 180,000 barrels per day, which can more than handle the 110,000 bpd of condensate being imported now and Enbridge is proposing an expansion.

And more:

The hard part, the bottleneck, is getting it to Patoka, where it can enter Southern Lights. Patoka, it turns out, is not particularly close to the biggest condensate-producing shale in the US, which is the Eagle Ford basin in Texas.

There are ways. For example, Plains All American is using the Louisiana port of St. James as a staging post to route Eagle Ford condensate into the Capline pipeline for shipment to Patoka.

Others are using existing gathering networks to move condensate to Corpus Christi on the Texas Gulf Coast, where it is loaded onto barges and transported to St. James. Magellan Midstream Partners and Copano Energy are taking this one step further, extending one of Copano's pipes by 140 miles to Corpus Christi. That line should soon be moving 100,000 barrels of condensate a day.