A Reader Comments On Advances In The Bakken -- Bakken 4.0 ---

Back on April 9, 2020, I posted an update regarding the CLR Weyland wells in Corral Creek.

Shortly after posting that, a reader shared thoughts regarding that production profile, specifically of #23786.

I should have posted the reader’s comments immediately but I wanted to take some time studying the comments before posting. Now that I've had a chance to do just that, here are the comments. Again, read the original post first (linked above). Here is the well and production data:

• 23786, 691, CLR, State Weydahl 2-36H, Corral Creek; t8/13; cum 381K 2/20;

Halo effect? That dreaded Bakken decline? #23786

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	2-2020	24	4886	4889	2667	4608	4136	462
BAKKEN	1-2020	31	6042	6045	3266	5913	5467	431
BAKKEN	12-2019	31	6899	6890	4377	8249	7236	992
BAKKEN	11-2019	30	5965	5956	4501	8346	7873	455
BAKKEN	10-2019	31	4074	4068	4770	4900	4804	86
BAKKEN	9-2019	17	2403	2399	3558	2812	2689	118
BAKKEN	8-2019	7	1671	1690	1298	1954	1910	41
BAKKEN	7-2019	31	8812	8806	6616	9278	9102	160
BAKKEN	6-2019	18	5275	5267	4302	4510	4305	196
BAKKEN	5-2019	23	3723	3733	4459	2596	2476	114
BAKKEN	4-2019	23	5943	5924	8433	5174	5055	103

Here are the comments from the reader:

That profile from well #23786 (above) may be a good example of how operators are utilizing the elevated, induced underground pressure derived from the injection of millions of gallons of water to 'push' the hydrocarbons towards the wellbore. 

Over that 8 month period (July 2019 to February 2020) the lessening amount of produced water shows that the original fracturing fluid has - to some degree (I would guess to a large degree) - been maintained underground. 

The little publicly accessible data that I have read leads me to conclude that little/no formation damage is now expected by keeping millions of gallons of water underground for extended periods. 

The latest iterations (constantly evolving) of the High Viscosity Friction Reducers  (HVFR) may be playing a large role.

Unrelated to the above, I am absolutely fascinated that first EOG and now WPX seem to be having the proppant component at the 19%/17% level of total mass of injected material. [Comment: I've been noticing the same thing.]

This is WAY higher than historical norms.

Couple of speculative musings ensue ...

The HVFR use enables a reduction in water amount with no corresponding dropoff in amount of proppant used. 

Reduced water amount - combined with the 'targeted' staging via Extreme Limited Entry Perforating (XLE) - allows highly controlled frac propagation that is now able to be closely monitored in real time.  

Operators may now be 'encroaching' (expanding?) new fracture complexity into the "outer" areas of parent well fractures using diverters, pump pressures and water volumes so as to not damage the older networks with the new fracturing.

Note ... gas lift seems to be the preferred artificial lift method now in the Bakken with both the traditional vertical portion using new, improved valves for vertical lifting and an additional, entirely new approach that extends tubing-within-tubing to enable gas injections all the way out to the toe which then sweeps the entire 2 mile long lateral with slightly pressurized gas. 

This sweeping mechanism could - theoretically - sweep up new, unwanted proppant/sand along with the desired liquid hydrocarbons ... aka oil. 

This would eliminate the chronic problems and limitations of normal Electrical Submersible Pumps (ESPs) due to sand-induced malfunctions.

This last is speculative on my part, but I believe the growing use of gas lift AL is playing a role.

Overall, the Bakken operators may be 'advantaged' with their lengthy operational history in this region alongside the ever present factors of innovation, risk taking, and resiliency.

There is so much in that comment. 

Take a look at these monster wells being reported this week,

• first, these wells, and, 
• then these wells.

I've been noticing this for the past couple of years. Say what you want, anecdotally, the wells in the Bakken are getting increasingly better and better (borne out by the EIA dashboards).

• 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

Now, this: starting about six months from now, we should start seeing even better Bakken wells that we've seen in the past year or so. The price of oil, at $20/bbl, WTI  (and it is likely to get worse) means that we are going to see significantly fewer wells being completed, and the wells that will be completed need to be incredibly good wells for operators to remain viable.

I can hardly wait to see the initial production numbers for wells that will be completed later this year. I think they're going to be quite remarkable.

One thing not mentioned by the reader: taking wells off line for 6 to 18 months does not seem to harm Bakken wells; in fact, generally speaking, it appears that Bakken wells taken off line for 6 to 18 months actually return to production quite nicely.