The Bakken is easily one of the most important sources of oil in the U.S. The shale play is located in eastern Montana, western North Dakota and parts of Saskatchewan and Manitoba, Canada, in the Williston Basin. Oil was first discovered in the play in 1951, but operators’ profits didn’t start booming until the past decade when operators began using horizontal drilling.

The Bakken region accounted for a little more than 10% of total U.S. oil production in November 2013, according to the U.S. Energy Information Administration (EIA). Furthermore, Wood Mackenzie predicts that oil production in the North Dakota and Montana sections of the Bakken and Three Forks formations will grow to 1.7 MMbbl/d in 2020.

While that goal hasn’t quite been met, North Dakota Bakken oil production was 914,003 bbl/d in March 2014 with 7,240 producing wells (126 bbl/d of oil per well), according to the North Dakota Department of Mineral Resources. According to February 2014 data on the EIA website, North Dakota is the second largest oil-producing state in the U.S. behind Texas.

In an April 2013 assessment, the U.S. Geological Survey (USGS) estimated mean undiscovered volumes of 7.4 Bbbl of oil, 190 Bcm (6.7 Tcf) of associated/dissolved natural gas and 530 MMbbl of NGL in the Bakken and Three Forks formations in the Williston Basin. This represents a significant increase over the estimated mean resource of 3.65 Bbbl of undiscovered oil in the Bakken Formation released in a 2008 USGS assessment.

At Hart Energy’s recent DUG Bakken and Niobrara conference in Denver, multiple presentations, panels and sessions focused on the increasing activity in the plays.

Technological improvements

Harold Hamm, the CEO of Continental Resources Inc., said he’s excited about the constant innovation happening in industry technology. “In 2000, we were running out of oil and gas, and then along came technology—horizontal drilling—and that saved us,” he said.

In a speech at the conference, Hamm expressed his confidence in technology’s ability to solve future problems as it has in the U.S. for centuries.

Technology certainly has had a hand in the success of Continental Resources. According to Hamm, dynamic company growth has been fueled by completions and production in two areas where horizontal drilling technology has made a difference—North Dakota’s Bakken and Three Forks and the South Central Oklahoma Oil Province (SCOOP) area in Oklahoma.

In 2007, Continental’s Bakken production was 8,580 boe/d, and in 2013 it was 88,250 boe/d.

“Back in 2009, people would ask us about how much of the Bakken has been developed so far, and I said back then maybe 12% to 13%,” Hamm said. “Now with the Three Forks and the lower benches, you can just about double the amount of wells being drilled. I’d have to say that now we’re less than 10% developed.”

Continental’s Hawkinson project is a new Three Forks development, and the company just completed an industry-first 402-m (1,320-ft), four-formation density test. At Hawkinson the 14-well program is underway, and other tests are currently drilling or in the completion stage. Formations to be tested include Tangsrud, Rollefstad, Wahpeton, Mack, Lawrence and Hartman, with the concept of 402-m spacings vs. 201-m (660-ft) spacings.

The company had about a 14,000 bbl/d initial rate from the prospect, Hamm said.

In 2009, the company had a goal to triple production during the next five years. “We accomplished that in about three and a half years,” he said. “Our next goal is to again triple production over the next five years, and that would put us at more than 300,000 boe/d and about 1.5 billion [barrels] on crude reserves.

“However, one of the biggest challenges remaining for the Bakken is infrastructure. We’d like to see the president and Congress pass the Keystone pipeline legislation, but we don’t think it will happen before 2016 and the elections. We think it will have to be built at some point, and we like to think that the president would include the passage of this pipeline as part of his legacy.”

Improved efficiencies

With the dramatic transition during the last decade from vertical wells to horizontal wells on single pad sites, a panel of E&P professionals said operators should now focus on finding the best ways to get more from each hole they put into the ground.

According to Chris Wright, CEO of Liberty Resources, “My personal belief is that the sometimes myopic vision of well costs using well as a unit cost as opposed to per-barrel cost has led to massive lost value opportunities in the Bakken. There’s just huge EUR upside. Most Bakken operators could increase their EUR by 50%.

“Fracturing is a different game now. Most of the changes in expenditures are not to buy more of the same thing but to spend more to increase frack intensity. The job, to us, is to bring our plumbing to get out as much oil as we can.”

One of Liberty Resources’ early clients, Brigham Exploration, made great gains by using greater fracturing intensity than other nearby operators. In one of the areas where it was operating, it had 50% more EUR than its neighbors, and in its “better areas” it had 60% more uplift vs. the average of its neighbors.

“If we increase our well EUR in our area by 10%, it’s a $2 million increase in the PV-10 of that drilling location,” Wright said. “A 50% increase is a $10 million increase in PV-10 of a drilling location for spending an extra few million.”

Francisco Fragachán, director of marketing and sales for pressure pumping for Weatherford, warned about steep production declines and wondered, “Is this due to reservoir quality or completion quality? EIA data indicate that sustained production from a rig point of view is that it takes 2.5 ‘rig times’ to sustain production.

“It’s an indication that there are opportunities for us to improve our completion effectiveness vs. efficiency. When you look at Eagle Ford statistics, it says that only 64% of the clusters are contributing to production. There’s a space for improved production and drainage.”

Adam Anderson, vice president of Western U.S. for Baker Hughes, agreed. “It strikes me how little we know about what we’re doing with so many of these formations. In terms of frack effectiveness, I think the prevailing wisdom is shifting toward more frack effectiveness, and in simple terms, we need to break more rock.”

Tom Lantz, COO of American Eagle Energy, said, “Bigger is not necessarily better, and I think it remains to be seen what the optimum design looks like, including refracturing, and we have to recognize the importance and variability, which will lead to different designs.

“Production from operators tends to vary across a field. One of the overriding predictors is the geology, and at the end of the day, the variability of each play can end up being part of the overall well production figures.”

But more fracking isn’t the only answer to improved productivity, Anderson said. “Productivity data in some fields vary, but early on in the Bakken sliding sleeves and openhole technology seemed to make sense and were efficient because of the formation’s natural fractures and because of nonpad drilling.”

For self-described “small guys” like Liberty, Wright said that “sleeves are fast and efficient, but for our company, which is about dollars per barrel, we’ve been using plug and perf from the start because our goal is to touch more rock by pumping multiple clusters with a small number of perfs and pumping at a very high rate.”

In regard to batch completions, there is a more prevalent trend toward zipper fracks and horizontal stimulation done on pads. Anderson said the trend adds greater efficiency to the operation. “For a service company, it certainly makes more sense to come out and do the operation once instead of waiting on other services,” he said.

On the topic of refracturing, Fragachán said that new spacings and perforation sites on the original well make a big difference. “We have to get back to some kind of mechanical isolation between stages so you can get better stages to more closely replicate the initial completion,” Anderson said.

However, Wright added, “It’s hard in a horizontal well compared to older vertical wells because we’ve got a bunch of stages, and it’s tricky and expensive. We got into the Bakken by refracking someone else’s well with nine-stage sliding sleeve completions and more than doubled the production, which told me that the Bakken is highly frack-dependent and that most of these wells are short on plumbing.”

Anti-flaring rule in North Dakota

The Bakken Shale has for several years been a stronghold of crude oil, rocketing North Dakota to second place in the rankings of the oil-producing states. Now the Bakken could add to the already accelerating growth of U.S. natural gas production, according to a recent report from Barclays Commodities Research.

The report cites a new rule in North Dakota that requires producers to cut natural gas flaring by 95% by 2020. In January, North Dakota captured only 64% of natural gas associated with crude oil production.

The report expects the newly captured volumes to result in greater gas output as midstream infrastructure catches up with the rapidly growing play.

“If gas output were to remain at January 2014 levels for the rest of the year and the share of captured gas were to rise from 64% to 75%, the output boost would amount to 140 MMcf/d [4 MMcm/d],” the report stated. “Assuming that production growth matches last year’s pace in 2014 but captured volumes rise to 75% over the course of the year, the state’s natural gas output could rise 250 MMcf/d y/y [7 MMcm/d year-over-year] in 2014. Similar production growth and a further increase of captured volumes to 85% would yield y/y production growth of 330 MMcf/d [9.3 MMcm/d] for 2015.”

Gas capture ‘the right thing to do’

Whiting Petroleum Corp. has flared down its Williston Basin operations, capturing all but 5% to 7% of gas associated with oil production, according to CEO Jim Volker. That’s low, considering the average across the basin is 30%. The environmental payoff is good, but the company also has figured out how to make the newest anti-flaring rules pay economically as well.

“We think it’s not only the right thing to do for the environment, but it’s the right thing to do for the shareholders,” Volker said during a question-and-answer session at the DUG Bakken and Niobrara conference. Volker pointed to the company’s 50% ownership of the Robinson Lake gas processing plant in the basin, which processes associated gas from both Whiting and from third-party operators. The company typically charges 20% to 25% to third-party companies, Volker said, “just as any midstream company would.”

The company is expanding the Robinson Lake plant from 1.4 MMcm to 1.7 MMcm to 2.8 MMcm (50 MMcf to 60 MMcf to 100 MMcf) gas capacity. The economics have been great for the company. “Basically, it’s a little like having a 20% to 25% free net operating profits interest in all the other wells that we’re gathering gas from,” Volker said. “A lot of people think midstream is somewhere typically between an eight- and 10-year payout. I think ours is going to be half of that. So that adds appreciably to the value we’ve created on that gas.”

Another hot topic discussed during the session was longer laterals. When asked if he thought lateral sections could go longer than 3,048 m (10,000 ft), Volker said that it’s already happening in the Bakken.

“Over in the Parshall Field east of the Sanish where we’re the operator, another operator is going that far and having good success,” he said. “I think it’s more predominantly a land issue than it is a technical issue. We have the ability to both drill that far horizontally and to frack that far by doing more stages. So there’s really no technical limit to that. It really has more to do with the size of the drilling spacing units that you put together originally.”