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North Dakota’s Bakken Still Years Away From Gas Utilization

Though most mature oil basins in the United States waste less than 1 percent of associated petroleum gas (APG), North Dakota says the still new Bakken play won't be able to reach that standard for several years.

North Dakota Governor Jack Dalrymple formed a task force in 2011 to reduce the amount of gas burned off in the state. Natural gas is a by-product of oil extraction and North Dakota still lacks the infrastructure to capture it for potential sale.

Dalrymple's office said gas processing increased from 225 million cubic feet per day to about 1.2 billion cubic feet per day between 2006 and the end of 2013, though North Dakota is still far behind the national average.

The Energy Information Administration (EIA) says more than 30 percent of the gas produced from the Bakken shale region in the state is flared or otherwise not put on the market because of a lack of pipeline capacity and processing facilities. That's compared with a national average of less than 1 percent.

Members of the task force have met more than a dozen times since it was formed to discuss ways to reduce the loss, which is estimated to be in the range of around $100 million per month.

Jeff Hume, vice chairman of strategic growth initiatives for Continental Resources, the largest stakeholder in the Bakken play, said in an interview that the industry task force is focused intently on finding the best way to move forward in the state.

"The goal of Continental and the industry as a whole has always been to sell all of our gas to a market," he said. "No one wants to waste hydrocarbons."

Related Article: Is This Issue About to Explode for Big Oil?

But it may be a tall order to reduce the amount of gas burned off anytime soon; the North Dakota government says it doesn't expect to see any new gas infrastructure in place until after 2018 at the earliest.

Alison Ritter, a spokeswoman for the state’s Department of Mineral Resources, said some of the energy companies working in the state might have to hedge their bets on natural gas.

"It’s a risk for a midstream company to over build infrastructure," Ritter told Oilprice.com. "Typically they need to find out what’s in place first, and then build the infrastructure."

Ritter said the percentage of gas associated with oil plays in the state varies from region to region, though most of the gas is expected to come from the heart of the Bakken and Three Forks areas.                                                                                              

Oil production might have to be curtailed, meanwhile, to keep flaring low. Continental, which said the Bakken play has already given up 1 billion barrels of oil, said state restrictions on production "are unnecessary," however.

The North Dakota Industrial Commission said production for February, the last full month for which data are available, was 951,340 barrels of oil per day and nearly all of that came from Bakken and Three Forks. Ritter said the state expects production to hit the 1 million bpd mark by June.

For gas, the state produced 1.06 million cubic feet per day in February, down slightly from the all-time high of 1.08 million cubic feet per day reported for November.

Related Article: Double-Digit Growth For U.S. Shale Explorers

Continental's Hume said his company flares about 10 percent of the gas it produces and attributes its ability to beat out the state average, which is around 35 percent, to working with midstream vendors who have the capacity on hand to deal with it.

In January, Dalrymple joined MDU Resources and WBI Energy in announcing plans to build a 375-mile pipeline that would carry gas produced from Bakken to residential customers and markets in the Midwest. Continental says Hess Corp. and ONEOK are working on similar infrastructure.

Ritter said North Dakota has set a goal of a 90-95 percent gas capture rate by 2020, though he cautioned that it's unfair to compare Bakken, a newer play, to legacy fields elsewhere in the country.

"The Bakken is still a relatively new oil field," she said. "We all want to see an end to unnecessary flaring, but it also takes some time for the necessary infrastructure to catch up."

By Daniel J. Graeber of OIlprice.com

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  • cas127 on April 30 2014 said:
    Forgive a simple question from an industry outsider (but observer) -

    Why can't the excess gas simply be re-injected?

    Isn't this sometimes done with older oil fields anyway - in order to increase pressure and extract more oil?

    Is it a function of cost more than technology? (Re-injection costs more than it is worth in terms of increased oil production...at $100 a barrel?).

    I agree that nobody would want to waste hydrocarbons and I understand that there is little current gas pipeline infrastructure in the hinterlands of ND.

    But why not store it for later use underground (locally) the same way nat gas is stored underground in other US locations.

    Puzzled by the lack of discussion in this area.

    As an outsider, I would think the future value of the otherwise flared gas (currently wasted) would more than offset the costs of re-injection/underground storage.

    What am I missing?
  • Roland on May 02 2014 said:
    Future value is unknown, present value is cheap. There are Federal regulations for pipeline gas. This means it must be processed to remove any H20, H2S, CO, CO2, & NGLs. Why not put an old jet engine on a semi trailer with a gearbox & generator, & sell (peaking?) electricity instead? Running wires is cheaper than laying pipe. Pipelines corrode.

    Reinjection requires compressors and (worse) drilling a non-producing injection well nearby. It's a revenue sink in most situations.
  • Shumberg on May 05 2014 said:
    The situation is crying for third party vendors who can turn dross into gold. That's how free markets work when not buried under nonsensical rules.

    Government regulations keep such things from happening. Government is a revenue sink in almost all situations.

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