Only In The Bakken: A Bakken DUC Out-Produces The Average Permian Well -- March 6, 2020

Comparing the Bakken with the Permian? Here are the dashboards --

EIA dashboards:

• natural gas storage 
• EIA pdf, Bakken: https://www.eia.gov/petroleum/drilling/pdf/bakken.pdf
• EIA, pdf, Permian: https://www.eia.gov/petroleum/drilling/pdf/permian.pdf
• EIA, pdf, Eagle Ford: https://www.eia.gov/petroleum/drilling/pdf/eagleford.pdf

A closer look at the two wells that came off the confidential list today:

• 35100, SI/NC, Oasis, 33-053-086100, Kellogg Federal 5297 12-30 8T, Banks, a DUC, but with huge production; 8.8 million gallons of water; 93.7% water by mass;
• 23958, 2,719, EOG, 33-061-02281, Liberty LR 107-1109H, Parshall, t9/19; cum 178K 1/10; 53 stages, 22.8 million lbs; 12.5 million gallons of water, 82% water by mass;
  

First, #23958, EOG, middle Bakken, 53 stages; 22.8 million lbs (no typo):

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	1-2020	31	21837	21770	36701	17556	17191	4
BAKKEN	12-2019	31	27128	27191	45940	15297	14970	13
BAKKEN	11-2019	30	35307	35346	59040	19680	17412	1918
BAKKEN	10-2019	31	38687	39180	72239	26707	24625	1716
BAKKEN	9-2019	25	55045	54159	95098	38709	37865	0

Now, #35100, Oasis, yes, it's still classified as a DUC. This is pretty good for a DUC:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	1-2020	31	13750	13753	25438	36120	34862	1041
BAKKEN	12-2019	31	18076	18073	31976	44105	41944	1943
BAKKEN	11-2019	30	18196	18197	34993	43173	42075	888
BAKKEN	10-2019	31	23457	23589	37556	51515	46564	4734
BAKKEN	9-2019	10	3059	2918	8109	5921	5832	20
BAKKEN	8-2019	0	0	0	0	0	0	0

Observations:

• mega-frack by EOG -- 22.8 million lbs of proppant; EOG has always pushed the envelope on sand; they had their own sources; first to build a terminal unloading facility in the Bakken, etc.
• and look at this: total gallons of water not all that high in that EOG mega-frack: only 12.5 million gallons; well, if they didn't use so much water mr-know-it-all, why did the proppant "weigh" so much -- look at the percent water to total amount of proppant -- 82%. Generally, operators use around 93% water by mass; sometimes as low as 87% but "never" as low as 82%; EOG used a lot of sand, but not that much more water than usual for the Bakken; sand weights 1.6x that of water;
• for a DUC, #35100 is producing nicely (yes, I know, technically it's no longer a DUC, it's been completed, but according to the NDIC scout ticket, still a DUC - SI/NC)
• #23958, back to that EOG mega-frack; it produced 55K bbls of crude oil in 25 days; extrapolates to 66K bbls in a 30-day month;
• neighboring wells to that EOG mega-frack; both neighbors not that close to the new well, but:
• one: a subtle jump in production; not much production increase, but nice to see a bit of a jump;
• the second: a larger jump in production; not huge, but more noticeable;
• the EOG mega-frack well on a pad with four locations to drill:
• one of the others is still LOC only; #33434;
• the other two are big producers but still on conf status (#33433, #33432)

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FracFocus

Links:
nice review, 2019;
2018;
2019;
minimal info, 2019;

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Commentary

Shortly after posting the original note (and before I added the FracFocus data and the links, I received this note from a reader (and that's why I added the FracFocus data and the links). I purposely delayed posting the reader's note to give me a chance to do some background. Here's the reader's comments:

Bit of a coincidence that, just today, I was reading a bit about a company touting its brand of High Viscosity Friction Reducer (HVFR) that could be variably tweaked to carry a LOT of proppant, if the operator so chose. 

Regarding this EOG well ... 12.5 million gallons water used for frac'ing is ~298 thousand barrels.

Yet, in just a few months, ~309 thousand barrels have been recovered.

I am wondering if EOG has uncovered a method to maintain VERY high pressure underground, deliver a VERY high payload of proppant, and not use an inordinately high amount of water to do this.

Several potential ramifications immediately come to mind ... one being a diminished halo effect (water not travelling/impacting adjacent wells).

Another consequence could be reduced incidence of frac hits (again, lowered water amount and MUCH tighter control of the frac geometry).

As you might say "don't want to get ahead of my headlights", but if my speculations are correct, this could usher in another iteration of well completion technology. Keeping an eye on this well's future production could be very informative.