The gusher of light, sweet crude oil flowing from North America’s unconventional shale plays has forced a major shift in how refiners—here and abroad—buy feedstocks.

Two downstream industry observers speaking in a spotlight segment at Hart Energy’s DUG Bakken and Niobrara conference in Denver agreed the biggest changes on the refinery landscape may be yet to come.

Odette Eng, global refining vice president for WorleyParsons Ltd., said refining is “going light,” adding “the tight-oil revolution has had the effect on the refining industry of a reversal” in a years-long trend toward heavier and higher-sulfur feedstocks. Domestic light oil is attractive in price and refiners, at least those who can, will be processing more of it.

But perhaps the biggest change downstream has been psychological, she said, adding, “crude supply no longer is deemed constrained.”

Some refiners will remain focused on purchasing heavy crudes, but the sources they buy from are changing. “Canada and Mexico are still viable,” she added, while other foreign producers already have seen a substantial drop in purchases by U.S. refiners.

The surge in U.S. light, shale crude production will continue to grow, she predicted, reaching 2.2 million bbl. per day by 2020.

Eng projected there will be more crude blending in the future as refiners mix lighter shale crudes with heavier oils to achieve medium-gravity feedstocks more compatible with complex refineries. Running light crude through complex refineries built to run heavy crudes creates high volumes of unfinished oils that refiners must sell at unattractive prices.

At the other end of the refinery business, refiners must respond to growing distillate demand, particularly road diesel. Gasoline demand, meanwhile, remains flat as drivers spend less time on the road and purchase newer, higher-mileage automobiles. Eng said that trend has led to growing U.S. gasoline exports since 2010.

Trisha Curtis, senior research analyst at the Washington-based Energy Policy Research Foundation, said the surge in shale oil production is likely to grow in the next few years.

“There’s a lot of potential, producers are getting more oil out than first thought,” she said.

That trend creates particular problems for Canada—already dealing with growing heavy oil sands output—because “every incremental Canadian barrel must be exported” due to the nation’s limited domestic crude demand. To compound the problem, “Canadian pipelines are essentially full, that’s why Keystone XL is so important.

“Heavy Canadian crude has to get to the Gulf,” Curtis added, which has substantial, complex refining capacity that can economically handle the heavy, high-sulfur crudes coming out of western Canada’s oil sands.

Curtis seconded Eng’s observation on falling light, sweet crude imports and projected all remaining U.S. light, sweet crude imports “will be displaced in the next couple of years.” Foreign light crudes from Nigeria and elsewhere will have to find new markets, probably in Asia.

She said the shift to crude by rail will continue with California offering a potential large, new market for oil moving to market by rail.

“The pipeline network (to California) is limited. Producers can’t get there by pipeline —and won’t,” she said.

Several California refiners await permits to build rail unloading racks that could supplement current supplies coming primarily from Alaska and in-state producers. However, California refiners face the same lightsweet vs. heavy-sour dilemma as many Gulf Coast refiners. Alaska North Slope and most California-produced crudes are at the heavy end of the oil spectrum and the state’s refineries have been built to economically process them.

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