In 2012, Statoil Oil and Gas more than doubled its Bakken production over 2011, but in 2013 the company’s Bakken output remained essentially flat with fourth quarter 2013 production of 49,900 barrels of oil equivalent per day, an increase of only 6 percent over the 47,000 boepd output in the fourth quarter 2012.
While those numbers might cause many Bakken operators to do some serious soul searching, especially during the current period of rapid development in the Williston Basin, for Statoil it is all part of the game plan as the Norwegian-based exploration and production giant takes a slower, longer-term approach to developing its onshore assets.
In an April 2013 conversation Petroleum News Bakken had with Stephen Bull, Statoil’s vice president for integration of Brigham into Statoil, Bull said doubling production in one year, especially in the middle of integrating Brigham into a much larger company, “was a pretty amazing feat.” When Statoil acquired Brigham in 2011, Bull said, Brigham was “on the ramp up,” operating as many as 19 drill rigs at one point.
However, for 2014, Bull said Statoil was looking to increase production some, but certainly not double it again. Statoil, he said, wants to avoid “super high” production peaks followed by “super high” decline rates he said are often seen in onshore oil production. Instead, Statoil wants to flatten its production curves over time.
With that mindset, Statoil cut back on the number of rigs operating in the basin in 2013 and began taking a more methodical approach to acquiring and evaluating drilling and completion data.
Learn before you leap
A key component of Statoil’s slower strategy in the Bakken is to take what it learns from drilling operations and apply that information to future drilling. To that end, Statoil cut down its rig count in the Williston Basin from 15 rigs in the first quarter of 2013 to five in the third quarter.
In an October 2013 conference call reporting third quarter financial and operational results, Torgrim Reitan, Statoil’s chief financial officer, said that with a smaller number of operating drill rigs, lessons learned from one Bakken drilling operation can more effectively be applied to other drilling operations in the play. “For us it’s very important to take a long-term perspective on that asset,” Retain said in regard to using a smaller rig fleet in the Bakken.
But that doesn’t mean Statoil won’t add rigs at some point farther down the road. “We’ll increase rigs, we’ll decrease them over time, and it will vary,” Bull told Petroleum News Bakken in April 2013. “It’s that kind of optionality that Statoil likes about the onshore business.”
Stay behind technology
Another facet of Statoil’s slower development approach is not to get too far ahead of technology. In the April 2013 interview, Bull spoke of the importance of slow but continuous application of technologies as those technologies develop. For example, Bull said that in the early years of development in the Norwegian continental shelf, recovery rates were in the 20 percent range, but as new additional uplift technologies developed, Bull said those North Sea recoveries are among the highest in the world reaching 70 percent and averaging 55 percent. “In the good old days of petroleum engineering, people wouldn’t dream that would ever be possible,” Bull said.
Not getting ahead of technology, Bull said, is another part of the company’s longer-term and more efficient approach to development. “That’s important for us,” Bull said, “because we think we can come back here and probably apply better technology and get more out of the rock than with current methods.”
Side-by-side frack testing
Throughout 2013, Statoil experimented extensively with slickwater completions comparing results to wells completed using gelled fluids, the method traditionally used by Brigham in the basin. After testing side-by-side slickwater and gel wells, Statoil found that in certain areas of its Bakken operations the slickwater-completed wells outperformed gel-completed wells. However, true to its convictions, Statoil reserved judgment.
In January 2014, Lance Langford, Statoil’s vice president for Bakken operations visited with Petroleum News Bakken about its frack testing and said the really hard part about conducting such tests is knowing how much data are enough. “It’s about a confidence level,” Langford said. “The longer you have production, the more confidence you have in your decision.” Langford said he likes to see at least 12 months of production data from wells before making any decisions about expanding a particular method to full-field development.
Langford said wells completed with slickwater tend to have longer but skinnier propped frack wings than gel-frack wells, and depending on formation thickness and rock properties in a certain area, slickwater fracks tend to extend more laterally than vertically. Gelled fracks, on the other hand, result in shorter frack wings but those frack wings tend to extend more vertically than laterally, and in certain areas, again depending on formation thickness and rock properties, fracking into the upper Bakken can enhance a well’s performance.
And because of the spatial variation in geology, Statoil separates its well performance data into subgroups within certain counties in both North Dakota and Montana. That allows Statoil to directly compare its own well data in a particular area to data acquired by other operators in the same area.
Going forward, Statoil will carefully evaluate results of its completion testing, and at some point in late 2014 or early 2015, Langford believes Statoil will have sufficient data to make decisions as to when and where slickwater completions may be applied to full-field development.
That approach, said Langford, is nothing new for Statoil in the Williston Basin. “It’s the same approach we’ve had since day one. We don’t want to change too many variables, and we don’t want to jump out and change what we’re doing that we know works too quickly because you make mistakes.”
Winning a race it didn’t enter
As a part of Statoil’s longer-term strategy for onshore development, the company focuses on flatter decline curves and does not intentionally go after high initial production, IP, rates. In the October 2013 conference call, Reitan said Statoil puts more importance on a reservoir’s long-term production rather than trying to maximize short-term production. Boosting initial production to high rates is easy in the Bakken, Retain said, but added that the high initial production can be followed by rapid decline.
That said, Statoil dominated 24-hour IPs in North Dakota in 2013. Statoil wells were among the top 10 wells with the highest IP in 35 of the 47 weeks that Petroleum News Bakken tabulated the top 10 IPs in 2013 (Petroleum News Bakken published biweekly in January and February before going weekly in March).
Even more impressive is the fact that Statoil wells topped the top 10 IP list in 19 of the 47 weeks it was complied, and three of those top 10 IPs were record highs. All three of those top 2013 IP wells are on the same pad in the Banks field, most of which lies in north-central McKenzie County but with a small portion extending north under Lake Sakakawea into south-central Williams County. The IPs of those wells ranged from 5,070 to 5,417 barrels. The latter, Statoil’s Beaux 18-19 7H, currently holds the highest IP on record in North Dakota.
At the end of 2013, Statoil held 312,000 acres in the Bakken. Most of the company’s North Dakota activity is centered in around the Banks field in McKenzie County and the Alger field in western Mountrail County. In Montana, Statoil’s activity is focused in the Elm Coulee Northeast field in Richland and Roosevelt counties.
