Saturday, February 14, 2015

Halo Effect Of Fracking, A Case Study In Truax Oil Field, The Wood Wells -- February 14, 2015


April 10, 2016: this area has been updated at this post.

Original Post
This should be fun for newbies and long-time readers. This is going to be a long post. I recommend getting out the popcorn and a beverage of your choice. Remember, I have no formal training or background in the oil and gas industry. This is simply my observations, my opinions, and they could be way wrong. I'm sure there will be landmen and roughnecks that laugh at my observations but that's fine. For all their hard work under very, very tough conditions, they deserve a bit of entertainment. However, if this information is important to you, talk to an expert.

We will start with the screenshot:

Here is the production profile for #19857, for the past year , completed / tested back in late 2011:
  • 19857, 1,533, Whiting, Wood 5-15H, t11/11; cum 220K 12/14; 
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
Look at the jump from September / October to November / December, 2014.

In the full month of 31 days in August, 2014, only 3,000 bbls. In November, almost 30,000 bbls.

By the way, did the well ever produce this much before November, 2014? Nope, not even immediately after the original frack -- production never got above 20,000 bbls, and here, after three or four years, this well produces almost 30,000 bbls in one month. This is the production profile for the first three months of this well, completed back in late 2011:


So much for "the dreaded Bakken decline rate." It maxed out at 18K its first month, and then several years later jumps to 30K in one month.

What's the story?

Go back and look at the screen shot of the GIS map where this well is located.

Note the horizontals that run alongside it: #28407 and #28386 or #28385. I can't tell from the GIS map for sure, but it's my hunch that the two horizontals running alongside are #28407 and #28386. (Whether it's 28386 or 28385 will make no difference.)

Here's 28407:
  • 28407, 1,339, Whiting, P Wood 154-98-4#-26-15-4H, 28 stages, 3.4 million lbs, t3/15; cum 51K 10/15;
Here's #28386 (similar profile to #28385 -- again, I can't tell for sure whether the horizontal parallel to the well in question is #28386 or #28385) (most likely it's #28385 based on legal description):
  • 28386, 1,930, Whiting, P Wood 154-98-1-27-34-16H, 19 stages; 4.8 million lbs; t10/14 cum
The production profile:

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Now #28385 (in case it's not #28386; #28385 is the more likely well):
  • 28385, 2,241, Whiting, P Wood 154-98-1-27-15-1H3, 22 stages; 4.6 million lbs sand; t10/14; cum
The production profile:

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

And that, folks, is called the halo effect of fracking.

Note the following:
  • the "old, existing" well  (#19857) was originally drilled/fracked in late 2011
  • the "old, existing" well (#19857) was taken off-line in mid-September and brought back on line in mid October, 2014
  • a "new, neighboring" well (#28385 or #28386) was fracked/completed/tested in October, 2014
  • the other "new, neighboring" well (#28407) is still on DRL status; it will be interesting to see when it was fracked, or the production profiles of neighboring wells if yet to be fracked
  • note the relatively low number of stages (19 stages for the old well; 22 stages for the new well); this tells me that there must be a fair amount of natural fracturing present (or other reasons for great production in the Truax (porosity, permeability, seam thickness, TOC, high pressure, etc)
  • note that the "old, existing" horizontal runs northwest to southeast
  • note that the "new, neighboring" horizontals run southeast to northwest 
The last two bullets are very, very interesting. I opined a long, long time ago that running new, neighboring horizontals in the opposite direction (heel-to-toe vs toe-to-heel) might have more of a halo effect than running in same directions.

Some other points to make:
  • again, there are only a few horizontals in these spacing units -- 3, 4, 5, 6 or so across the Bakken. Imagine the halo effect when 24 wells (and more) are drilled in one spacing unit (remember, there is a case on the NDIC dockets requesting upwards of 60 wells in one spacing unit
  • these particular wells were part of the KOG package bought by Whiting
So, now "we" have two things to think about when talking about "the dreaded decline rate" in the Bakken:
  • halo effect of fracking new wells near existing wells (not only horizontally separated, but also vertically separated); and,
  • re-fracking existing wells
And we haven't even begun to talk about EOR.

By the way, back to the halo effect of fracking. This opens up a whole new area of discussion. Is it more cost effective to re-frack an old well, or more cost effective to drill and frack a new well that neighbors older wells. At some point, they will drill/frack a horizontal midway between two older neighboring wells and perhaps get a jump in production in the two older wells as well as great production in the new well.

The Bakken has a lot more stories to tell.

And this is another story, 7-month-old Sophia:

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