Whiting Petroleum’s Mark Williams Looks at Bakken History

Bakken: The Advance of Technology is What this Is Really All About

Day four at the 2016 EnerCom conference featured Mark Williams, Whiting Petroleum’s SVP exploration and development, giving a historic perspective of the Bakken that showed how Whiting’s collective knowledge base has grown and developed from the beginning of the Bakken exploration phase to Whiting’s development of the play.

Whiting Petroleum, which was founded in 1980, is a legacy player in the Williston basin. Williams was able to track the earliest predictive model of oil generation and expulsion for the Bakken shale to Colorado School of Mines adjunct professor Fred Meissner in 1984-1985. Williams presented an image of Meissner’s early hand-drawn map of the play.

Williams said that Whiting and EOG drilled two simultaneous wells in the Bakken in April and May of 2006. Whiting employed a single stage “Hail Mary” completion, at the same time that EOG had brought up multi-stage completion technology from its work in another basin and used it on its Bakken well.

Williams described the Middle Bakken as a “pressure sandwich” between the Upper and Lower Bakken formations. He said that from the beginning of the Bakken exploration and development, “we had a tremendous appetite for looking at core—you can’t get all the information you need from logs.”

From the beginning, Whiting’s reliance on geoscience helped the company make strong decisions about how to most efficiently develop its Bakken assets. Williams talked about the evolution of completions technology and some of the improvements that taught the company how to coax more oil from every well, while simultaneously reducing costs.

Williams used two images from Whiting’s scanning electron microscopes (SEMs) to point out the difference in completing the Bakken shale versus the Niobrara.

“Relative to other unconventional reservoirs, you could drive a truck through a Bakken pore. It’s very large, very well connected by fractures. But the Niobrara is a little bit different: the pores are much, much smaller but the key is there’s a whole lot more of them.”

Williams said the company’s SEMs showed them that there was “twice the amount of pore space, twice the amount of oil in place per unit volume of rock” [in the company’s Niobrara assets compared to the Bakken].

“The problem though should be obvious—it’s the connectivity between these pores. We had started drilling in the Niobrara but we weren’t yet getting very good results. We had templated our fracs from the Bakken down to the Niobrara; we were doing at that point about a million-pound, two million-pound fracs,” Williams said.

“It was quite obvious after seeing this image what we needed to do: we needed to increase our frac sizes. So we went all the way up to six million pounds originally; and we’ve come off of that now – we’re down to four to five million pounds typically.  Once that happened it allowed us to take off and run with that play. That became our standard size of our jobs and it allowed us to go into development mode at Redtail [Whiting’s Niobrara asset in Colorado].

“So for the past few years it’s really been all about optimizing the completions. We shifted to cemented liner completions; that allows us to get good isolation – to make sure the frac that we’re doing went through the perforations directly into the reservoir without having to deal with all this annular volume between the reservoir and the liner, which causes a lot of complications. It allowed us to get much more precise with our fracs.”

Williams said that high volume, slickwater fracs became the norm back [in 2015], and Whiting gradually made the transition into higher volume sand fracs as well. “That’s been really the big driver in the past year and a half, or so.”

“A focus on stimulation technologies continues to be the primary driver in the play today—increased fracture complexity that we’re getting out of slickwater fracs, and then doubling and even tripling the amount of sand,” Williams told the EnerCom audience.

If you look at the 141 wells that we’ve drilled since early 2015, about a third of those wells have our modern completions. We’ve taken our fracs in the Bakken from about 3.5 million-pound fracs up to a minimum of seven [million pounds] all the way up to about 13 million pounds. That’s led to about a 140% improvement in our wells.

“We’re using diverting agents to distribute the frac load much more efficiently.” Williams said that Whiting has more than doubled the amount of entry points in its wells. “We’re doing a much better job of distributing our frac flow up and down the well bore.  That allows us to drill on tighter spacing. [By doing so] “you’re doing a much more rapid job of draining the reservoir.”

“As I see it, the advance of technologies is what’s going to continue to drive shale plays in the U.S. and I think that’s where we’re going to see the greatest amount of growth across the world. We’ve been completing globally in markets, but we’re going to be competing with ourselves.”

“It’s amazing to me that we can drill a well 7,000 foot deep and 7,500 feet laterally in the Niobrara today in four days—four days.  In my career I never thought that day would come, but it is here. … I think we’ve probably solved about 80% of the problems in drilling technology.”

“Completion technology is where we are right now – I think with the advances we’ve made we’ve maybe solved half of that problem; and there’s more we can do.

“The next phase is mapping, it’s customizing completions. It’s customizing the reservoir rock to the fluids contained in that reservoir, to the completion fluids that we’re using to do the frac. [We’re] looking at the physical and chemical compatibility of those three pieces to try and customize the frac to each individual reservoir.”

Williams said he is a strong proponent of re-fracs. He said Whiting had allocated $15 million to doing re-fracs, they have done five re-fracs already, and the company has about 1,400 more wells to do them in.

“We originally felt like 10% was a pretty good threshold for these unconventional reservoirs; we’ve pushed that already with completion technologies up to 10%-20%. I think we can come close to doubling that in the future with advanced completion technologies,” Williams said.

Mark Williams’ webcast presentation at the EnerCom conference is available to view and download here.

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