More midstream projects than you might expect are “goin’ on” in the Western Canadian province of Alberta, considering the challenges that bitumen/crude oil and natural gas producers there continue to face. There are several drivers behind the relatively long list of oil and diluent pipelines; gas processing plants and fractionators; and oil/NGL storage facilities being built in Canada’s Energy Province, but much of the work is being done to meet the expected needs of oil-sands expansion projects approved during better times and set to come online soon. Today we begin a blog series on Alberta midstream projects with an overview of where the province’s energy sector stands today.
Producers in Alberta—the heart and soul of Canada’s energy sector—have had a rough go of it lately. In May, wildfires swept through parts of the oil sands region, forcing temporary shutdowns at several production sites that initially reduced the oil sands’ output by more than 1 MMb/d—or about one-third the area’s pre-fire production level. Output wasn’t back to near-normal until mid-summer (see Back in the High Life Again), and surely the dislocations and damage caused by the fires (which scorched more than 1 million acres) have had more lasting personal (and business) effects. Oil sands producers already had been dealing with low oil prices, which have hit them harder than most because their hydrocarbon-extraction processes more complicated and costly than their shale-play counterparts. Also, the Alberta oil sands are further away from most major refinery centers, particularly the U.S. Gulf Coast, and bitumen producers need to either add “diluent” (usually field condensate or natural gasoline, a.k.a. plant condensate or pentane plus) to their bitumen to allow it to flow through pipelines, or transport low-viscosity bitumen in special “coil” rail cars that can be heated before unloading—added costs that make $41/bbl oil an even more bitter pill to swallow.
It hasn’t been much better for Alberta natural gas producers, who control tremendous gas reserves in the Duvernay, Montney and other plays in the Western Canadian Sedimentary Basin (WCSB) but who have been stymied in their efforts to find new markets. They continue to face tough competition (from Marcellus/Utica producers) in their traditional Ontario and U.S. Midwest markets, as well as repeated setbacks to their hopes of moving gas west and exporting it as liquefied natural gas (LNG) to Asia (see One Way or Another). In response, some Alberta producers have shifted their focus to the most liquids-rich—or “wettest”—parts of the Montney and Duvernay plays, where they can produce significant volumes of field condensate and natural gasoline, which as noted above are in-demand bitumen/heavy-oil diluents in the nearby oil sands. At recently drilled Encana wells in the Duvernay, for instance, roughly half of the production (on a barrels-of-oil-equivalent basis) is condensate (darker-green layer in Figure 1), with most of the rest being natural gas (orange layer) and the smaller balance (lighter-green layer) being lighter NGLs like ethane (C2), propane (C3), and normal butane (C4).
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