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Vol. 18, No. 15 Week of April 14, 2013
Providing coverage of Bakken oil and gas

Long-term player

Statoil looks at its Bakken assets from a slightly different perspective

Mike Ellerd

For Petroleum News Bakken

Since acquiring Brigham Oil and Gas in 2011, Norway-based Statoil has been establishing itself as a major player in the Williston Basin. But with decades of experience in global offshore development, Statoil has a slightly different philosophy when it comes to onshore production. Moving slower rather than faster is part of that philosophy.

London native Stephen Bull is Statoil’s vice president overseeing the integration of Brigham into Statoil, and in that role he is very much involved in Statoil’s Bakken operations. Bull spoke with Petroleum News Bakken on April 9 about Statoil’s Williston Basin operations along with the company’s long-term business model and how that model applies to its Williston Basin assets.

Long-term business model

Statoil’s business model, according to Bull, is to take a longer-term view of onshore production, an approach he describes as somewhat anathema in the onshore world.

“We’re long-term investors, so we don’t shy away from 10 to 20-year horizons and even more. And we’re used to this with the offshore world. As you know, finding oil and gas in the offshore world takes at least 10 years to actually start getting the production going, and then you expect another 20, 30 maybe 40 years of production after that. So we think in terms of decades in our investment horizon.”

Bull adds that the slow and continuous application of technology is very important. He says in the early years of North Sea development recovery rates in the Norwegian continental shelf were in the 20 percent range. But through technological advances that provided additional uplift, such as CO2 flooding, those average Norwegian continental shelf recovery rates, he says, are now the highest in the world, averaging 55 percent with some fields yielding up to 70 percent. “In the good old days of petroleum engineering, people wouldn’t dream that would ever be possible.”

For the Williston Basin, Bull says Statoil is looking at its assets as a long-term investment and is not in a hurry to drill those assets out. “These are long-term assets and Statoil has always been a long-term sustainable player in whichever area we’re in,” he says. “Drilling up everything immediately is not what we really want to do.”

Bull says Statoil wants to avoid the “super high” production peaks followed by “super high” decline rates that are often seen in onshore production. Instead, he says, Statoil wants to “flatten” those curves over time. “That’s important for us because we think we can come back here and probably apply better technology and get more out of the rock than with current methods.”

Core area

Statoil presently holds 378,000 net acres in the Williston Basin, 258,000 of which are in North Dakota with the remainder in Montana.

Most of the North Dakota acreage is centered north and south of Williston in Williams and McKenzie counties, and in central Mountrail County. Bull says these are Statoil’s core areas in the basin. The acreages there are well connected, which he says is important for gathering systems.

In Montana, Statoil’s acreage is concentrated in Richland and Roosevelt counties. Bull says the company wants to hold that acreage, but adds that it is not presently focusing on its Montana assets. “But really we’re just looking to drill out the best acreage that we can first, and then we’ll come and do the infill over time.”

2013 development and production goals

As Petroleum News Bakken reported in February, Statoil’s Williston Basin production increased from 21,000 barrels of oil equivalent per day in 2011 to 47,000 boepd in 2012. When Statoil acquired Brigham in 2012, Bull says, Brigham was “on the ramp up,” and at one point had as many as 19 rigs operating.

“Doubling production within one year was a testament to the organization,” he says. “Right through the middle of integration with a bigger company, and to actually keep those operations going and double it was a pretty amazing feat, it really was, and do that safely as well.”

But Statoil is not looking to double production again in 2013. Bull says Statoil has developed its production targets for 2013, and although the company has not yet made those targets public, he said the goal is for a net production increase in 2013, but not to double it.

In 2012, Statoil drilled approximately 150 wells in the Williston Basin, but Bull says that number will be slightly lower in 2013. He expects the rig count to average around 12 for the year, down one rig from the end of 2012.

The slight reduction in drilling activity, he says, is due to increased drilling efficiencies, but also to the Statoil’s “portfolio” business approach where the company balances drilling activity among its various U.S onshore operations, including the Eagle Ford and the Marcellus. “We’ll increase rigs, we’ll decrease them over time, and it will vary. It’s that kind of optionality that Statoil likes about the onshore business.”

Much of the increase in drilling efficiency comes from walking drill rigs, Bull says, and Statoil has now moved exclusively to walking rigs in the Williston Basin, completing that transition in 2012. “We spent most of 2012 swapping out those old rigs for the new walking rigs, and we really do see a lot of efficiencies there. It makes a big difference.”

Pad densities

Statoil’s “base case” for pad density, according to Bull, is seven wells per pad in a “four by three” configuration with four wells targeting the Bakken formation and three targeting the Three Forks. However, Bull says Statoil is looking to increase pad density moving forward and is currently involved in a reservoir and fracture modeling study with Schlumberger looking into well densities and communication between well bores.

“There is a lot of upside in adjusting those densities over time,” Bull says. “It shows the level of development the Williston Basin is in. Even though it has been drilling up slowly and surely since the 1950s, we’re still in the experimental stage I think — the rest of the players as well — to look at new benches and also looking at increasing the density as well.”

A preference for rail

Statoil started shipping oil out of the basin in September and is now shipping almost exclusively via rail. Most of that oil is going to the East Coast because, according to Bull, that is where Statoil is seeing the best price differentials. In addition, he says, Statoil is looking at the possibility of shipping Bakken crude to California and even Washington state because the West Coast is another high-price market.

“Rail is the big thing for the next three or four years until we see other companies invest and put more pipelines in the ground or reverse pipelines or other options such as moving oil through Canada.” But in the mean time, he says, with oil getting backed up in the region, rail is the answer.

Other target formations

Like other companies, Bull says Statoil is also looking at the possibility of targeting other intervals or formations in the basin and not just the Bakken and upper Three Forks. He says Statoil will do some experimenting itself, but it will also follow what the rest of the industry is doing and understanding about other horizons.

As he puts it, “We could do a lot of research and science into these things but I think actually putting a well bore through it, fracking it and understanding it and doing the research afterwards is the best way to understand this rock.” But exactly what other intervals or formations Statoil might be looking at in the future — “Ask me again in five years,” Bull says.

Flaring and gas infrastructure

Like everyone else in the Williston Basin, Statoil is working to reduce flaring.

“From a Norwegian perspective, you’re not allowed to flare — you’ll be taxed,” Bull says. “There was a CO2 and flaring tax put in on the Norwegian continental shelf decades ago, and it’s influenced the business that we have in Statoil.”

Bull says that Statoil knows flaring is an important issue in North Dakota, and that the key to flaring is to have the pipeline systems and processing capacity, but that, he notes, is the problem in the Williston Basin because the basin is still in the early stages of development. However, he is optimistic that the infrastructure will be built.

“We think over the next few years it will be a better situation. We’ll see a lot more infrastructure and a lot more money put in the ground from Oneok and other partners as well.”

Natural gas task force

In another approach to flaring, Statoil has put together a task force from its research and development team in Houston and operations people both in Austin and Williston to look at how the company can increase its use of natural gas in its Williston Basin operations. Not only is this effort intended to better address flaring, Bull says, but also to cut carbon dioxide emissions. As he notes, “Running a drill rig on diesel fuel puts out a huge amount of CO2.”

The task force, Bull says, is looking at how natural gas could be developed on a long-term basis in the basin, including compressing natural gas, not only to run drill rigs but also possibly for lift to increase reservoir recovery. In addition, he says, it may even be feasible to operate vehicles on compressed natural gas. He says Statoil is currently working with third party consultants and other companies that might want to invest it what the company sees as a “more sustainable business” for the basin.

“We’re trying to imagine what this industrialization could look like for the basin for the long-term.”

This does not mean to imply that Statoil will get into the CNG business, Bull says, but instead the company will look for those who can get into that market and see how that market can be incentivized on the long-term. “There is a huge possibility, there really is, you’ve just got to think big of how this business is going to be.”

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