The Challenges Of Calculating Breakeven Points In Tight Oil Fields -- December 16, 2018

See this post for background and full production profile.

The well:

• 16677, 101, MRO, Beck 24-8H, Bailey, initial frack, open-hole with 500K lbs sand; 45-stage re-frack in 2017 with only 5.8 million lbs sand, t12/07; cum 172K 10/18;

Disclaimer: I am inappropriately exuberant about the Bakken.

This well was a lousy well by any measure when it was first drilled. We talked about that at the time, but it fulfilled its role: a) it provided geologists an opportunity to look at the geology of the drilling unit; and, b) it held the lease by production for ten years. 

Back in 2007 most of the cost was in drilling the well; the stimulation costs should have been minimal: open-hole stimulation with around 500,000 lbs of sand. Big deal. LOL.

Wells back then were taking up to 45 days or more to drill, from spud to completion. Wow, think about that. Now they are drilling these wells in six days, fourteen days max, and then shutting them in, to come back and frack a group of wells, each frack taking three to five days.

This well was off-line most of its life and would have cost little to maintain.

Then in 2017, it was re-fracked with a small amount of sand, less than 6 million lbs. The operator essentially got a brand new well for the cost of small frack.

The operator did not have to go through the laborious process of obtaining surface rights; mineral rights; building a new pad; building a ten-mile road out to the site; bringing in electricity; putting in a new natural gas fractionator; etc; etc; etc. All the infrastructure was done. In fact, it's possible there are water lines in some areas negating multiple water truck runs. Some areas have waste water pipelines in place. And the cost savings go on and on.

One can calculate the break even cost(s) of this well going all the way back to 2007, but those costs have long been "booked." Anything prior to 2010 is certainly ancient history, some might argue.

On the other hand, some might argue that the break even costs of oil coming up from that well after the re-frack is the "new" break even cost. I don't know.

This is the beauty of drilling in the Bakken. Chevron calls these projects "short-cycle projects." Operators can pick and choose which wells to re-frack based on many factors. The WTI spot price is simply one factor, and perhaps a minor factor in the overall scheme of things.

There are many ways to figure break even costs in tight oil.

In the Permian, and in the Bakken, to some extent, there is even another huge variable. I'll let readers think about that for awhile. A reader mentioned it the other day. 

But what I love most about this well, as noted above: this well was a lousy well by any measure when it was first drilled. Many readers talked about that. Wondering why operators kept drilling wells like this. We talked about that at the time, but this well and many others like it fulfilled their roles: a) these wells provided geologists an opportunity to look at the geology of the drilling unit; and, b) these individual early wells held the lease by production for ten years.