Subtle Change In CLR's Proposed Horizontal Placement In The Better Bakken?

There are certainly some observant and some astute readers out there.

Take a look at these graphics.

• CLR Graphic, October 18, 2013, 160- and 320-acre pilot density projects.
• CLR Graphic, April 24, 2013, proposed well pattern, increase density.

I believe the proposed well pattern on those two graphics are the same; if not, the differences are very, very subtle.

Dan, earlier today, told me to take a look at a recent case before the NDIC:

Case 21582, CLR, 21582, application of CLR, for an order amending the field rules for the Bear Creek, Cabernet, Corral Creek, Crooked Creek, Jim Creek, Oakdale, and Rattlesnake Point-Bakken Pools, Dunn County, ND, authorizing a total not to exceed fourteen wells on each existing 1280-acre spacing unit within Zones II and III in the Bear Creek-Bakken Pool; Zones III and IV in the Cabernet-Bakken Pool; Zones II, III, and IV in the Corral Creek-Bakken Pool; Zones I and II in the Crooked Creek-Bakken Pool; Zones I, II, III, IV, V, and VI in the Jim Creek-Bakken Pool; Zones I and II in the Oakdale-Bakken Pool; and Zones I, II and III in the Rattlesnake Point-Bakken Pool; a total not to exceed fourteen wells on each 1920-acre spacing unit in Zone VII in the Jim Creek-Bakken Pool; and Zone IV in the Rattlesnake Point- Bakken Pool; and a total not to exceed twenty-eight wells on each existing 2560-acre spacing unit within Zone V in the Corral Creek-Bakken Pool; Zones VIII and IX in the Jim Creek-Bakken Pool; Zones III and IV in the Oakdale- Bakken Pool; and Zones V and VI in the Rattlesnake Point-Bakken Pool, eliminating any tool error requirements and such other relief as is appropriate.

Look at the graphic and see if you see the subtle difference that Dan noted:

Now that I look at it again (for the umpteenth time), maybe the difference is not so subtle.

I've talked about this from the very, very beginning: how fracking should work 360 degrees radially, and should impact other horizontals if drilled within 300 feet or so. But I had not noted the new well pattern proposed by Continental Resources in this case, on the December, 2013, dockets.

For those that don't see the change, here it is: in the earlier links, horizontals in the MB and TF2 were "stacked" directly above each other; while horizontals in the TF1 and TF3 were offset from MB and TF2 and "stacked" directly over each other.

In the newer, proposed configuration, none of the Three Forks horizontals are directly below the middle Bakken horizontals.

In addition, none of the TF wells are "stacked" directly in line with each other: all horizontals are off-set.

It certainly looks to me like this should optimize fracking the entire drilling unit.

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Also note that the horizontal distance between the middle Bakken wells are 1,320 feet. I've always felt that 500' radially was the maximum distance that fracking was effective, or 1,000 feet between wells. It certainly raises the question, twenty years from now, whether it would make more sense to re-frack the existing middle Bakken wells (1,320 feet apart from each other) or drill/frack new wells between the existing middle Bakken wells. I remain convinced that fracking a new well in the vicinity of an existing well, improves the production of the existing, older well.

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Regardless, using the same spacing it is easy to see that one could put in additional wells in the above graphic:

• TF1:  two additional 1/2 wells on the drilling unit lines (one net well)
• TF3: one additional full well

Thus, 16 wells on a 1280-acre spacing unit, or as many as 32 wells on a 2560-acre spacing unit.

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See, also a recent post on XTO and KOG leading the charge on increased density projects:

....numerous operators are seeking authority from the commission to drill up to 30 wells on existing 2,560-acre spacing units, up to 16 wells on existing 1,280-acre units, and up to four wells on existing 320-acre units.