Oil-sands expansion projects coming online and the resulting need for more diluent are among the drivers behind a number of midstream infrastructure projects in the province of Alberta, including natural gas processing plants and fractionators; oil and diluent pipelines; and oil/NGL storage facilities. The total volume of work is surprising, considering the fact that oil-sands production economics are iffy right now, if not downright upside down. Today, we continue our look at midstream projects under development within Canada’s Energy Province, this time focusing on gas processing and fractionation facilities.
In Part 1 of this series, we discussed the tough times that producers in Alberta’s oil sands region have been experiencing. Devastating wildfires in May temporarily reduced production by more than one-third, and low oil prices the past two years have hit oil sands producers harder than most because their hydrocarbon-extraction processes are more complicated and costly than their shale-play counterparts. Add to that the extra costs they face because of their distance from most major refinery centers, particularly the U.S. Gulf Coast, and because of 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 as a diluent/bitumen blend known as dilbit, or transport low-viscosity bitumen in special “coil” rail cars that can be heated before unloading (see Parallel Lines). When oil prices are low, every dime of extra production cost or transportation cost hurts. And then there’s the plight of 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 losing market share to Marcellus/Utica producers in their traditional Ontario and U.S. Midwest markets (see One Way or Another). They’ve also faced repeated setbacks to their hopes of moving large volumes of Alberta gas west and exporting it as liquefied natural gas (LNG), though on September 27 (2016) the Canadian government finally approved (with nearly 200 conditions) the plan by Petroliam Nasional Berhad (Petronas; Malaysia’s state-owned energy company) to build Pacific NorthWest LNG, a large liquefaction/LNG terminal planned for a site near Prince Rupert, BC. (Petronas still hasn’t committed to building the project, however, due to the current––and still-worsening––glut of worldwide liquefaction capacity.)
There is cause for optimism that a number of smaller energy infrastructure projects entirely within Alberta’s borders will get built. A few years ago, when oil prices were much higher (and projected to remain high), oil sands producers committed to more than a dozen projects to expand bitumen output, these long-lead-time projects––which are adding about 850 Mb/d of production capacity in the 2015-19 period––are coming online. Most important to the midstream sector, these projects are driving the need for more diluent, either in the form of natural gasoline (a natural gas liquid––or NGL) or field condensate (superlight crude oil), as well as spurring development of oil and diluent pipelines, and of oil and diluent storage capacity. As we said last time, Alberta Energy Regulator (AER) has estimated that in-province demand for diluent will increase 200 Mb/d (from the current 550 Mb/d to 750 Mb/d) by 2021 as the oil sands expansion projects come online and ramp up to full production. Alberta’s current diluent needs are being met to a significant degree by out-of-province sources—almost all from the U.S., with the vast majority of the deliveries being made via Enbridge’s 180-Mb/d Southern Lights diluent pipeline from Manhattan, IL (south of Chicago) to Hardisty and Edmonton, AB, and via Kinder Morgan’s 95-Mb/d Cochin Pipeline from Kankakee, IL (also south of Chicago) to Fort Saskatchewan, AB (see Part 2 of our Parallel Lines series for more on Southern Lights and Cochin).
In the past year or two, though, Alberta gas producers have been focusing increasingly on “wet” gas and field condensate production in the province’s Montney and Duvernay plays. For example, about half of the production (on a barrel-of-oil-equivalent basis) from recently drilled Encana wells in the Duvernay has been in the form of natural gasoline or field condensate. In the Montney, Encana wells that started producing in 2016 get an average of 75 bbl of plant or field condensate for every MMcf of gas––seven times the condensate-to-gas ratio than in the company’s base/pre-2016 wells. By the end of 2016, Encana expects to be producing 50 Mb/d of condensate in the Montney alone.
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