WILLISTON - Natural gas that is flared today could one day be used to extract more oil from the Bakken.

The Energy and Environmental Research Center at the University of North Dakota is in the early stages of studying enhanced oil recovery using natural gas.

“We’re actually very encouraged about this at this point,” said John Harju, associate director for research. “We do know that several companies are at least studying this.”

The EERC has been researching injecting carbon dioxide into Bakken wells to enhance oil recovery, and estimates that the technique could mean billions more barrels of oil produced in North Dakota.

But the state doesn’t have enough carbon dioxide available currently, while at the same time about one-third of the state’s natural gas is burned off at the well site due to a lack of infrastructure.

Preliminary lab research shows that injecting raw gas into the Bakken wells may also be an effective way to recover more oil, while reducing flaring at the same time, Harju said.

There is substantial economic drive to develop enhanced recovery methods. Under current technology, companies are recovering about 4 percent to 6 percent of the oil in place, Harju estimates.

“Very small changes in that recovery percentage translate to billions of barrels of oil,” he said.

Injecting carbon dioxide into Bakken wells reduces the viscosity of the oil, Harju said.

“Oil that’s trapped in really tiny pore spaces, essentially will kind of pop out of them and become more mobile because of that lowered viscosity,” he said. “You’re changing the chemical properties of the oil in some way, allowing it to be more effectively produced.”

The EERC estimates that injecting 2 billion to 3.2 billion tons of carbon dioxide into Bakken wells would produce an additional 4 billion to 7 barrels of oil, Harju said. He anticipates companies will begin pilot projects as early as this year.

However, the total amount of carbon dioxide being generated in the state from power generation stations is 33 million tons per year, Harju said. That means it would take up to 100 years to have enough carbon dioxide to fully implement the enhanced recovery method, he said.

“We do believe CO2 will be a better working fluid, but its scarcity is a real challenge, whereas these rich gas streams are much more available, and at least at the moment they’re very much economically challenged,” Harju said.

Companies are currently looking at laboratory studies and engineering models to use natural gas for enhanced oil recovery, Harju said. He anticipates that companies will begin doing pilot tests this year.

“It is the kind of thing that could be implemented fairly quickly in certain cases where you might have some of this opportunity gas in close proximity to fields that could put it to use,” he said.

Projections for enhanced oil recovery are part of engineering firm KLJ’s study that’s being prepared for the Legislature’s Interim Energy Development and Transmission Committee.

The study includes projections for oil development for the next five years, using input from industry, state agencies and the EERC.

KLJ CEO Niles Hushka told legislators last month that the firm doesn’t expect to see substantial efforts toward carbon dioxide enhanced oil recovery during the next five years.

However, the industry is experimenting with using methane for enhanced recovery at high levels because it has some of the same properties and is available on site, Hushka said.

In the long run, as more infrastructure to capture the natural gas is developed and carbon dioxide becomes available, EERC researchers believe carbon dioxide will be more viable for enhanced oil recovery.

“If you think about this over the long term, this is probably a very, very expensive working fluid for (enhanced oil recovery),” Harju said of natural gas. “However, today, it’s obviously economically challenged given the amount that’s going to flare.”

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