HOUSTON -- North America has a long history of hydrocarbon revivals. In the’70s, there was the Arctic and Prudhoe Bay. In the ’80s and ’90s, there was the upsurge in the Gulf of Mexico deepwater. In the late ’90s and 2000s, there was the Canadian oil sands. And now there is the shale gas and tight oil boom. Never mind volatile pricing, the import/export debate or the ever-present environmentalists: When it comes to North American energy, hydrocarbon revivals are our thing.

“This is not a new phenomenon of new production or resurgence in production in North America,” said Andrew Slaughter, vice president of upstream research at IHS. “The question we’re dealing with now is ‘how is this different?’”

Slaughter posed the question before introducing EOG Resources CEO Mark Papa, who spoke as part of a plenary session on North American energy abundance at IHS’s CERAWeek in Houston last month. EOG was one of the first movers in the horizontal Barnett gas play in Texas and among the first to make the technology work in the Bakken oil play.

The U.S. will have the lowest long-term natural gas prices of any industrial nation for up to 50 years. “This is not a flash in the pan. We believe there are sufficient reserves that are generated from these shale plays in both the U.S. and Canada to allow us reserves for at least 50 years of domestic supply,” Papa said. He added that the U.S. has saved $100 billion a year on gas, compared to Europe and Asia. “If you think our economy has been limping along the past couple of years, think how much worse it would have been had we not had the $100 billion of relief that’s being driven by the shale gas revolution.”

The U.S. could be North American crude oil self-sufficient by 2020. “It’s now obvious to everyone that shale oil has changed the calculus of the entire U.S. import picture, and it’s going to be a long-lasting situation,” Papa said. The U.S. will continue to rely on Canadian imports at a higher level than it does now, as Canadian exports grow. Papa also encouraged greater natural gas vehicle use in the future to ensure hydrocarbon self-sufficiency.

Condensate cannot displace crude oil. “Condensate is a different animal than crude oil in refining processes. And when you look at the EIA data, it’s gathered together...And you really need to split it up,” he said. Thirty percent to 40% of growth in the Eagle Ford, which Papa projects will surpass the Bakken in two years, is condensate growth. “Condensate growth in the U.S. is certainly going to change the regional price differentials quite a bit.”

New Eagle Ford or Bakken-sized black oil plays are unlikely, but more combo plays are likely to be discovered. “The combo plays could consist of 30- to 40% crude oil, maybe 30% natural gas liquids and the rest dry gas,” according to Papa. “And we think there are substantial plays still left like that in North America that are indeed undiscovered ... We think that the Wolfcamp play in the Delaware basin in West Texas and southeast New Mexico could develop into a substantial-sized play.”

Improving recovery is the next technical focus. “Right now, our estimated recovery factor from the Eagle Ford shale is 8%,” Papa said. “We believe 8% is going to get us 2.2 billion barrels of oil net back to EOG. Obviously, when you’re in the petroleum business, 8% is a pretty low, pretty pathetic recovery factor, and we’re working on ways to improve that recovery factor through some sort of secondary recovery, and that’s the horizon you see in the shale plays.”

Shale success outside North America is likely to be slow. “Nine years after the first Barnett shale horizontal gas success, no one has yet made commercial success with either oil or gas in a shale play outside North America,” Papa said, adding that EOG is cautious about horizontal drilling in the international arena. “One of the keys is you have to be able to drill thousands of identical wells at a low individual well cost, and those circumstances don’t necessarily exist in a lot of locations.”