Fast-growing Kodiak Oil & Gas Corp. is a 100 percent North Dakota asset play; it has divested its Montana acreage and is now 100 percent invested in North Dakota.
“We are a pretty straightforward story, Bakken 100 percent: Everything we have is now North Dakota,” said Lynn Peterson, Kodiak chairman, president and CEO in remarks during an Oct. 1 conference call. “We have divested everything we have had in Montana, so we are 100 percent North Dakota.”
Peterson said Kodiak now has more than 190,000 net acres in the Williston Basin with seven company-operated drilling rigs active, as well as a 50 percent interest in another rig with ExxonMobil. He said Kodiak will continue to run seven rigs utilizing two full time completion crews through the rest of the year.
Kodiak will spend about $1 billion on 100 wells in 2013, Peterson said, adding that in his opinion the company will meet the lower end of its production guidance of 30,000 to 34,000 barrels of oil equivalent per day on average for the year.
“Today, we are producing somewhere around 36,000 to 38,000 boe per day; with our two completion crews going through the fourth quarter here we expect to exit the year north of 40,000 barrels,” Peterson said.
Peterson said the company is continuing to work on reserves and it has seen large reserve increases over the course of the year.
169% compound growth
According to an October slide presentation Kodiak had pro forma proved reserves of 144 million boe on June 30, reflecting 86 percent crude oil. The company has experienced a 169 percent compound annual growth rate of its reserves since 2009, the company said.
Kodiak’s Dunn County acreage is the company’s premier acreage, Peterson said, with an estimated ultimate recovery per well of 850,000 boe up to 1 million boe. The Koala, Smokey, and Polar areas in the middle of the Williston Basin follow with EUR profiles of as much as 850,000 boe, he said, adding that the wells there are performing “extremely well.”
On the southwest edges of the Williston in Divide County, Kodiak has a smaller acreage position with EUR profiles of 350,000 boe to 450,000 boe, Peterson said.
Peterson said his best wells were in the Bakken formation but Kodiak had had some very good Three Forks formation wells.
“Generally speaking, I think our Three Forks are a little bit inferior to our Bakken, and we have always spoken to that fact, but (we are) generally pleased. ...”
Peterson said the company had a limited number of Three Forks formation wells on its Dunn County acreage; some are competitive with Bakken formation wells.
“Clearly,” he said, “One of the better wells is Three Forks.”
Spaced down wells
Peterson said Kodiak’s down spacing program was indicative of where the basin is headed.
“We chose to do two of these projects” he said. “We did one in our Polar area, just east of the city of Williston,” adding that in the Middle Bakken formation, well spacing was 800 feet apart which allowed for six wells to be drilled in each of the 1,280-acre spacing units.
In the Three Forks formation, the company also employed an 800-foot horizontal separation, but with a twist — the wells were alternately drilled into the middle, and into the upper Three Forks.
Kodiak said earlier in 2013 that it had observed evidence of “communication” between Bakken wells during fracture stimulation and it revised its well-completion procedures to strengthen production of nearby wells and increase recoverable reserves.
Based on the observations Kodiak decided to temporarily shut down all producing wells within the immediate vicinity of new wells being completed, saying the gains outweighed the temporary production delays.
Convinced of communication
After completion of the two down spacing projects, Kodiak remains strongly convinced of the communication effect between wells.
“Our interpretation of the Three Forks quite frankly is that, we believe that when we frack the well, and … we are seeing communication (from the second bench) into the upper member. We look at this as kind of one large tank of oil,” he said. “I don’t believe it really differs from a lot of industry statements.
“There are some people that talk more of these being different benches, separate reservoirs; we don’t feel that way,” he said. “We don’t think it really matters at the end of the day, because you are going to need more wells to drain the same amount of oil.
“Again as I look at these down spacings, I think our entire team is excited, what we have seen,” Peterson said. “We have not seen a degradation of reserves here in our opinion at this point.”
Peterson said the company’s next pilot project will experiment with even tighter well spacing.
A series of four wells will be drilled from a pad — two wells in the Middle Bakken member, and two wells in the Three Forks. The wells will be spaced about 600 feet apart which may allow for seven wells to be drilled in each of the 1,280-acre spacing units.
“If we are successful and if it looks right, this would allow us to put a seventh well into each of these formations,” Peterson said.
Spending efficiently
Of the company’s $1 billion capex plan, about 10 percent will be spent in the outlying Grizzly and Wildrose areas, Peterson said.
“The bulk of our money is going right into the heart of the play, principally in the Polar, Koala and Smokey areas, and again it’s a reflection of our two down spacing programs, where we did a 12-well program in each,” he said.
Peterson said the company has made great progress on reducing its average cost per well over the course of the year.
“As we entered the year where we are probably running $10.5 million to $11 million (per well), today I think that number is probably at $9.5 million,” he said. “We certainly had our wells pushing down to the ($9.2 million and $9.3 million) number, and I think as we go through the fourth quarter our goal is to try to reach to the $9 million type number.
“When we give you these numbers — these are full producing wells — that’s putting wells on production, so that includes our resurface facilities,” he said. “We use 100 percent ceramics and really 90 percent, 95 percent of our acreage, so again, it depicts the entire well costs.”
Peterson said the bulk of the well cost improvements were due to a reduction in average drilling days per well. Two years age, drilling days per well averaged more than 30, he said, as compared to a number in the high teens presently.
“Our target is to get to 15 days per well,” he said. “Again, all these things will help us push these well costs down, closer to the $9 million range.”
Peterson hopes to employ what the company has learned as it beefs up its acreage position in the Bakken. He said the company currently holds and is focused on obtaining quality acreage, rather than the sheer number of acres held.
“We have really challenged our team to buy and look for quality acreage.”
