"Water Flooding" In The Bakken -- June 7, 2020

I forget when, but within the past year, I suppose, a reader started noting something strange about the water that returned to the surface in the first few months after a well was fracked.

Example: these two wells were both completed in December, 2019, and both were completed in the same oil field, the Sanish. It may or may not be important to note that one well was completed in the middle Bakken, the other in the Three Forks. I think it may be relevant.

Look at the amount of water returned after the wells were fracked.

In the first well, as much as 84,000 bbls in one month (the 3-day return of 9,510 bbls extrapolates to 95,100 bbls of water over thirty days) was returned.

Now look at the amount of water regurgitated in the second well in the same period of time right after the well was fracked.

First, this well:

• 36754, 1,322, Kraken, Candace 15-22 1TFH

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	4-2020	30	26735	26815	49447	0	0	0
BAKKEN	3-2020	31	29954	30416	84028	29415	13105	15939
BAKKEN	2-2020	11	3305	2784	40380	3398	2278	983
BAKKEN	1-2020	3	3895	4048	9510	3972	3172	756
BAKKEN	12-2019	30	33569	33263	300	33570	15760	17382

Second, this well:

• 36130, A, Whiting, Harvey TTT 41-4HU, Sanish, t--; cum 137K in five months:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	4-2020	30	26995	26968	3861	27947	27889	26
BAKKEN	3-2020	31	27511	27499	7364	22333	22093	210
BAKKEN	2-2020	29	29643	29677	9038	20518	19188	1303
BAKKEN	1-2020	31	31093	30998	8779	25914	6718	19165
BAKKEN	12-2019	21	21326	21148	11028	13332	0	13308

I may be seeing something that doesn't exist or reading more into it than the phenomenon deserves, but the amount of water being regurgitated among different wells is certainly fascinating. It has to be by design.

A reader commented on this:

Regarding 'novel water flood' in recent  wells ...

This is a brief rundown with what may be happening ...

1. One principal -- tied to Extreme Limited Entry perforations -- isolates individual stages that have rock which will 'open up' the pre-existing fissures within a range of pressure, say 1,500 psi. 

Another stage may have rock that will 'open up' at 1,000 psi. 

Another at, say, 2,000 psi.

These stages may vary from 120 feet in length to 350 feet, but the KEY component will be the point at which the needed pressure opens up the fissures. This characteristic is determined by several methods of measurement while drilling, along with years of experience.

2. The skillful use of 'far field' diverters temporarily blocks the horizontal spread of the fracturing. 

NOW, the operators are maintaining an 'open up' pressure in a 500 foot half length (from each side of the wellbore) while NOT having unwanted growth into the adjacent well's drainage.

Incorporating ultra tiny microproppants enhances the scouring/opening in this precise region of rock. This is where all that extra proppant has been going.

3. Final principle -- due to newest High Viscosity Friction Reducers (which do not damage formation when left 'in the ground' for many months) -- the artificially elevated formation pressure (akin to your 'water sweep'observation) now drives the oil which has come out of the rock (incredibly vast 'spider webby' fractures are now possible with aforementioned techniques) and produce high/very high oil production for many months.

4. Throw in the near ubiquitous use of gas-lift Artificial Lift, and this may explain some of the very high numbers from Continental, Kraken, Marathon, and others.

Most of the above is informed speculation, but it is probably a fairly accurate description of what is taking place.

I replied to the reader that I have a gut feeling of what is going on in the Bakken -- involving these "new" principles as well as additional factors -- but cannot articulate it as well as the reader does, and I certainly don't have the background or access to journal articles or papers which might support some of my thoughts. But literally reporting the IP and cumulative production of every well that comes off the confidential list, day in and day out, certainly gives one a feeling of the improvements that are being made. 

Another Huge CLR Carson Peak Well -- June 6, 2020

Important note: note the amount of returned water. A reader noticed this phenomenon in the Bakken about a year ago. Very, very, very interesting. This, along with XTO's look at communication between neighboring wells, different formations, after fracking is very, very intriguing.

The well:

• 35272, 3,376, CLR, Carson Peak 4-35HSL, Oakdale, t6/19; cum 445K 4/20; huge well, middle Bakken, 40 stages; 16.1 million lbs;

From the file report:

• spud date: October 29,2018
• TD date: November 10, 2018
• curve: began early morning November 1, 2018; completed 22:20 on November 1, 2018; one drilling assembly;
• lateral
• drilled out of the shoe late in the evening of November 3, 2018
• intermittent flares, 5' - 15'
• gas buster brought on line; gas ranged from 900 to 4,000 units; peaks as high as 5,000 units after first trip; three BHAs required;
• very high gas; 
• 100% of the lateral remained in the middle Bakken
• 2560-acre spacing

Full production:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	5-2020	31	39982	40040	7603	69274	68352	247
BAKKEN	4-2020	28	40282	40311	7821	61240	58760	1939
BAKKEN	3-2020	31	54291	54224	10515	76077	64319	11295
BAKKEN	2-2020	25	37475	37504	7667	43876	35673	7901
BAKKEN	1-2020	31	41058	41092	8899	45559	43114	2103
BAKKEN	12-2019	31	35783	35772	9164	39931	37392	2130
BAKKEN	11-2019	30	31906	31870	7266	30733	25839	4553
BAKKEN	10-2019	31	34680	34668	8246	28889	15674	12878
BAKKEN	9-2019	30	35591	35588	9369	34781	27403	7006
BAKKEN	8-2019	31	42880	42876	12029	40905	33894	6657
BAKKEN	7-2019	31	47954	47932	14889	47232	40808	6067
BAKKEN	6-2019	20	38292	38137	11628	32326	24424	7528
BAKKEN	5-2019	0	0	0	0	0	0	0
BAKKEN	4-2019	0	0	0	0	0	0	0
BAKKEN	3-2019	0	0	0	0	0	0	0
BAKKEN	2-2019	0	0	0	0	0	0	0
BAKKEN	1-2019	8	5037	5037	2851	2618	0	2618

Completion Strategies, Bakken 4.0, Whiting, WPX -- March 29, 2020

Completion strategies, Bakken 4.0, Whiting. For more, see completion strategies, Bakken 4.0, linked at the sidebar at the right.

Case studies, two WPX wells coming off confidential list this next week:

• 36502, drl, WPX, Skunk Creek 1-12HW,  33-025-03824, South Fork, t--; cum 8K over 23 days; fracked 1/9/20 - 1/17/20; 4.9 million gallons of water; 83.3% water by mass; friction reducer, 0.02466, extremely low on a percentage basis;

• 36503, drl, WPX, Skunk Creek 1-12HA, 33-025-03825, South Fork,  t--; cum 10K over 22 days; fracked 1/8/20 - 1/17/20; 4.9 million gallons of water; 83.4% water by mass; friction reducer: 0.02537, extremely low on a percentage basis;

Example of portion of FracFocus report:

Frack data that catches my attention:

• total gallons of water, less than 6 million gallons or more than 12 million gallons
• percentage of water by mass: less than 88% or more than 92% 
• friction reduction by percent: less than 0.04000 or more than 0.05000 (a reader brought this to my attention, thank you very much)

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)

*************************************

FracFocus

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

*******************************

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.

Production Data And Completion Data For One Of The Slawson Torpedo Federal Wells -- November 26, 2019

The Slawson Torpedo Federal wells are tracked here. Completion strategies since 2018 are tracked here.

Here is the production data for one  of the twelve wells on this pad. The well:

•  31275, 3,632, Slawson, Torpedo Federal 7H, 70 stages; 12.95 million lbs; Big Bend, , t12/18; cum 158K 9/19; 

Production profile:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	9-2019	13	11005	11104	10256	8043	6700	65
BAKKEN	8-2019	30	36713	36822	34255	24885	20429	379
BAKKEN	7-2019	16	21967	21908	722	16964	14450	79
BAKKEN	6-2019	30	49441	49380	48345	31178	21013	4740
BAKKEN	5-2019	24	31076	31233	20467	18438	11258	3782
BAKKEN	4-2019	0	0	0	0	0	0	0
BAKKEN	3-2019	0	0	0	0	0	0	0
BAKKEN	2-2019	0	0	0	0	0	0	0
BAKKEN	1-2019	0	0	0	0	0	0	0
BAKKEN	12-2018	6	7340	6721	15832	823	0	0

Shifting The Focus To Optimized Production -- November 17, 2019

Beginning with the abstract sent to me by a reader I did a google search for relevant articles hoping to learn a bit more about drilling locations and completion strategies in the Bakken.

Springer, September 23, 2019: growth drivers of Bakken oil well productivity. The full article currently available. One may want to archive it before it disappears. Wow, wow, wow -- a light bulb goes off -- it comes down to technology and geology. The former is dynamic, the latter is static. Let's look at geology. In all the articles I have read, this seems to be the progression:

• the oldest articles compared basins around the world -- akin to macroeconomics in the business world
• with the shale revolution, articles began to compare various basins in the US: the Haynesville, the Marcellus, the Permian, the Eagle Ford, the Bakken, etc. -- again, macroeconomics
• most recently, analysts are comparing "areas" within a basin, such as areas owned by certain operators, or in the case of the North Dakota Bakken, the four or five major counties
• I don't follow the other plays closely enough to say, but in the North Dakota Bakken, for whatever reason the state regulators decided to define fields, it has worked out incredibly well;
• it seems like a no-brainer but studies are still faulted for comparing McKenzie County with Williams County, for example. Each of those counties is relatively huge; and different fields within each county vary significantly in quality.  

The second light bulb that goes on: in this paper, wells from 2010 through 2017 were analyzed. I'm sure the researchers factored all that in but I think including wells drilled in 2010 with wells drilled in 2017 is like comparing apples to oranges. Too much to think about. Time to move on. [Later: see first comment.]

Denver Well Logging Society, Spring, 2019, workshop.

Hart Energy, one year ago, September 4, 2018: shifting the focus to optimized production. Operators see opportunities for production gains in legacy wells, refracturing, and data analytics.

• caption at the linked article: Equinor will deploy artificial-intelligence powered artificial lift technology on its rod pump wells in North Dakota
• there is evidence that operators might be pumping as much proppant into the well as they can can and that laterals have extended so long that it might not be economic to drill out much farther
• the phrase "reached a point of maximum return" is tarting to show up more often
• so, if operators have reached "maximum return" with regard to sand, where do they go next?
• Equinor -- machine learning/artificial intelligence

in late July (2018) Equinor announced it will deploy a rod lift technology developed by Ambyint—a company that specializes in artificial lift and production optimization equipment— on its wells in the Bakken Shale, where Equinor will expand the system to full-field development.During pilot testing, Equinor was able to automate rod pump well optimization through the use of Ambyint’s autonomous set point management functionality, according to a press release. By identifying wells that were overpumping or underpumping, controller set points were adjusted “with minimal human interference,” the release stated.

• legacy well optimization:
• pumping improvements (see article)
• workovers
• managing chokes
• it's not the highest EUR, but the highest IRR
• well refracturing
• Oasis experience in the Bakken (see article)
• artificial life trends (see article)
• analytics (see article) -- may be the biggest payoff
• well bashing -- relationship between "parent" and "child" (see article)
• again, Oasis in the Bakken

Oasis’ Reid said that in North Dakota the company is applying full-field development strategies, so Oasis does not have much activity cycling in the same area, which helps allay the effects of well bashing.

“We generally have one parent well in each of our DSUs, and when we come in for development drilling we are drilling out the full DSU at all depths in the Bakken and Three Forks to minimize future interference effects,” he said. “In addition, we are often refracking the parent well to improve its performance and to minimize the disruption to the new wells from a depleted parent well.”

Another Oasis Aagvik Well Coming Off Confidential Today -- May 7, 2019

Fracking note: see the fracking data for the Oasis Aagvik well coming off confidential list today -- 50 stages BUT slightly less than 4 million lbs sand.  Completion strategies in the Bakken are tracked here.


Deal: Anadarko accepts OXY's new bid; Chevron has four days to counter-offer. Huge loss for Chevron is they lose this deal. Consolation prize: Chevron will get a $1 billion break-up fee. Part of the new offer cy OXY was to sell Anadarko's Africa assets to Total for $9 billion. 

SRE: beats by 29 cents; misses on revenue. Press release here.

BA: Boeing fell almost $5 yesterday; looks like it will lose almost another $4 today.

Disclaimer: this is not an investment site. Do not make any investment, financial, job, travel, or relationship decisions based on what you read here or think you may have read here. 

****************************

Back to the Bakken

Brent: down 1.33%; trading at $70.29

Wells coming off the confidential list today -- Tuesday, May 7, 2019: 24 wells for the month; 119 wells for the quarter

• 35306, SI/NC, Hess, BL-Domy-156-95-2932H-10, 
• 35305, SI/NC, Hess, BL-Domy-156-95-2932H-9, 
• 35199, 2,799, WPX, North Mabel 2-35HF, Mandaree, t3/19; cum 21K 28 days;
• 34036, 543, Oasis, Aagvik 5298 41-35 2TX, 50 stages; 3.969 million bls; Banks, t11/18; cum 95K 3/19;
• 32510, 173,  BR, CCU Mainstreeter 5-1-25MBH, Corral Creek, t3/19; cum --

The Oasis Aagvik wells are tracked here. 

Active rigs:

$61.53	5/7/2019	05/07/2018	05/07/2017	05/07/2016	05/07/2015
Active Rigs	62	61	49	27	85

RBN Energy: factors affecting feedgas demand and LNG exports in 2019.

Reason #1 Why I Love To Blog -- A Reader Explains MRO's Lower Number Of Stages -- April 4, 2019

Earlier today I asked if anyone was paying attention? I was unable to explain why MRO is consistently fracking with fewer stages (and therefore [?] less sand).

A reader who has provided many insightful and helpful comments over the years sends this explanation.

Regarding MRO's lower stage count ... the March issue from American Oil and Gas Reporter (aogr.com) contains an outstanding piece targeting Oasis' Elkhorn Field in the Bakken for a look into cutting edge fracturing/completion practices. The full link: https://www.aogr.com/magazine/editors-choice/engineered-completions-key-to-economic-development-of-elkhorn-field.

I have read the uber wonky piece twice and will need further reading in attempting to 'get' what is occurring, but - essentially - operators are maintaining 1,500/2,000 psi pressure between the wellbore's 'edge' (entry point into the formation) and the ever-expanding fracture tip. 

This is accomplished by the precise placement and number of entry points (clusters) and employing diverters (temporary plugs) in order to contain the frac (vertically and horizontally) while maintaining a very high pressure.

The effective accomplishment produces a VERY rubbilized (sic) formation within a tightly constrained area.  This essentially is what Mark Papa has always sought.

Liberty Resources is a leading innovator in this regard and has some papers online discussing this approach.

Incredibly the full article is accessible without hitting a paywall. To be safe, I've archived it.

The buzz-phrase in the last six months has been the "problem" with "parent-child" interference. This article also addresses that issue.

This is an incredibly important article for those trying to better understand the Bakken.

A huge "thank you" to the reader for sending this. It truly made my day. Best article all day. All week? Maybe.

I believe Mark Papa (former CEO of EOG) is now CEO of Centennial Resource Development:

Centennial Resource Development, Inc., an independent oil and natural gas company, focuses on the development of unconventional oil and associated liquids-rich natural gas reserves in the United States.

The company’s assets primarily focus on the Delaware Basin, a sub-basin of the Permian Basin. Its properties consist of acreage blocks primarily in Reeves County in West Texas and Lea County in New Mexico. As of December 31, 2018, it leased or acquired approximately 80,223 net acres; and owned 1,597 net mineral acres in the Delaware Basin. The company was formerly known as Silver Run Acquisition Corporation and changed its name to Centennial Resource Development, Inc. in October 2016.

From Bloomberg:

Mr. Mark G. Papa has been the Chief Executive Officer at Centennial Resource Development, Inc., (Formerly, Silver Run Acquisition Corporation) since November 2015 and has been its Chairman since October 12, 2016. 

Fracking -- Completion Strategies -- 2018 - 2019

Fracking: strategies going into Bakken 4.0 starting March, 2020. Link here. 

Fracking Strategies, 2018 - 2019

A lot of the links will be identical. At the linked sites, one may have to scroll through the list of wells to find specific examples.

Slawson:

• middle Bakken, Big Bend, 70 stages; 12.95 million lbs; see this post;

MRO:

• Three Forks, first bench, Reunion Bay, 45 stages; 7 million lbs (and less); see this post;
• March, 2020; see this post;

EOG:

• middle Bakken, Clarks Creek: 57 - 60 stages; upwards of 19 million lbs; 100 mesh sand
• middle Bakken, Parshall: 45 stages; 9.4 million lbs; 
• March, 2020; see this post; and this post; and, here;

Hess:

• middle Bakken, Manitou; 60 stages; 8 million lbs; large/medium white sand

Bruin:

• Three Forks, B1, Antelope-Sanish: 55 stages; 14 million lbs
• Three Forks, B1, Antelope-Sanish: 50 stages; 14 million lbs 
• middle Bakken, McGregory Buttes, 55 stages; 14.4 million lbs 
• middle Bakken, Lone Tree Lake / Ellis, 50 states; 14.5 - 15.1 million lbs

Nine Point Energy:

• middle Bakken, Squires, 60 stages; 10 million lbs 

CLR:

• Three Forks, first bench, Elm Tree, 81 stages; 15.6 million lbs;
• middle Bakken, Elm Tree, 80 stages; 20 million lbs
• middle Bakken, first and second bench, Three Forks; Ravin wells in Dimmick Lake: 62 stages; 10 - 17 million lbs;
• middle Bakken, Pershing: 51 stages; 8 million lbs
• Three Forks, B1, Pershing: 51 stages; 8 million lbs
• Three Forks, B1, Banks: 57 stages, 6 million lbs
• middle Bakken, Corral Creek: 60 stages; 10.8 million lbs
• Three Forks, H2, Corral Creek: 56 stages; 10.6 million lbs
• middle Bakken, Elm Tree: 64 stages; 15.9 million lbs
• Three Forks, B1, CMC, 68 stages; 10.6 million lbs 
• middle Bakken, CMC, 40 stages; 8 million lbs

Oasis:

• Three Forks, Banks: 50 stages; 4 million lbs
• Three Forks B1, Sanish: 50 stages; 10 million lbs: 
• middle Bakken, Sanish: 50 stages; 10 million lbs
• Three Forks, Willow Creek: 40 stages; 6 million lbs 
• Three Forks, Banks, 50 stages, 4 million lbs 
• middle Bakken, Banks, 50 stages; 3.96 million lbs;

BR:

• Three Forks, Corral Creek: 31 stages, 10.2 million lbs;
• middle Bakken, Corral Creek: 32 stages; 8.6 million lbs;

Enerplus:

• Three Forks, Moccasin Creek: 33 stages 6 million lbs
• middle Bakken / Three Forks, Mandaree: 33 stages 6 million lbs 
• middle Bakken, Antelope-Sanish, 42 stages; 10 million lbs;
• TF1, Antelope-Sanish, 43 stages; 15.6 million lbs;

Whiting:

• Parent-Uplift (the "halo" effect) -- first presentation ever, 1Q19
• Generation 5.0; also, here; here;
• Generation 4.0
• 8 million lbs; 40 stages  

Whiting:

• southwest Bakken
• Pronghorn/Three Forks
• older wells: 30 stages; 3 million lbs
• 2018, Park oil field: 45 stages; 5.1 million lbs

Lime Rock Resources:

• middle Bakken, Fayette: 50 stages; 5.9 million lbs

Abraxas, from the company's January 2019 corporate presentation -- frack strategy history:

Mike Filloon On Bakken Well Completions -- September 6, 2017

Note: there is much more to this article than what first meets the eye (as they say). There are some interesting points that Mike mentions without further elaboration. It's been a long time since Mike has had an article specifically devoted to the North Dakota Bakken. Archived.

***************************

An article from Mike Filloon that I've been anticipating, over at SeekingAlpha. Summary:

• lower oil prices might not be enough to stop production increases in the Bakken, which may be bearish for the USO
• increased use of proppant and fluids continues to improve production in concert with plug and perf with cement liners
• when enhanced completions are considered, the economics are much better than expected
• look for operators to move to newer designs exclusively in the Bakken and other U.S. plays

From the article:

The Bakken was one of the first plays to be developed in the US. It has been the focus of unconventional production, but has fallen out of favor. First the Eagle Ford then the Permian have both provided better economics. Newer plays like the STACK/SCOOP have emerged.

All have seen additional CAPEX, with dollars leaving the state of North Dakota. This has been seen by players like Continental. The Bakken is well suited for a well design analysis. It has seen more development than any other play, and this provides a longer term history.

The Bakken provides an excellent sample of well design. It shows why oil prices have not recovered, and why US production continues to increase at $50/bbl. 

North Dakota Bakken well completions:

• moving from ceramic to sand (I'm also seeing a move to smaller sand from bigger sand)
• using more sand overall
• using more slickwater
• the number of stages are increasing

The average location in this grouping has or will produce 208 KBO in the first 19 months of well life. We used a D&C of $6 million and $10/bbl in costs. The average well reaches payback within this time frame at $50 oil and $3 natural gas.

Now I'm waiting for Mike to discuss the peculiarities of the Bakken, i.e., the reversal of the dreaded decline rate.

4Q16 Wells Updated -- March 17, 2017

Disclaimer: in a note like this there will be typographical and factual errors. Do not make any investment, financial, job, travel, or relationship decisions based on anything you read here. If this information is important to you, go to the source.

I just updated most of the IPs for 4Q16 wells still on drl or SI/NC status. I didn't keep track of the number of Statoil wells still on SI/NC status, but there were about five of them, and none of them were completed; Statoil has not completed any of its SI/NC wells since the last update (date unknown but probably six months ago) that were reported in 4Q16. Note: the data is through January, 2017; obviously reporting and paperwork lags behind what is happening in the field.

Note the amount of sand EOG uses. And, again, XTO has a non-impressive well for the completion solution (see the same thing 3Q16). 

These are the updates for all the wells I looked at; I went through the entire list. All of these were on SI/NC status.

XTO:

• 32619, 150, XTO, Johnson 31X-6FXG, Siverston, Three Forks, 40 stages, 7.6 million lbs, t10/16; cum — 

WPX:

• 30653, 1,755, WPX, Helena Ruth Grant 33-34HT, Reunion Bay, Three Forks, 41 stages, 6.1 million lbs, t12/16; cum 66K 1/17;
• 29081, 1,830, WPX, Helena Ruth Grant 33-34HW, Reunion Bay, geologist report says Three Forsk; frack says TF, 38 stages, 5.9 million lbs, t12/16; cum 62K 1/17;
• 29082, 2,397, WPX, Helena Ruth Grant 33-34HA, Reunion Bay, 40 stages, 6.1 million lbs, t11/16; cum 83K 1/17;

Petro-Hunt:

• 26974, 1,269, Petro-Hunt, Kostelnak 145-97-29B-32-2H, 50 stages, 4.9 million lbs, t11/16; cum 28K 1/17;

EOG:

• 32140, 854, EOG, Ross 43-0915H, Alger, 46 stages, 14 million lbs, t2/17; cum --
• 32137, 990, EOG, Ross 106-0915H, Alger, 52 stages, 15.66 million lbs, t2/17; cum --
• 32138, 1,352, EOG, Ross 42-0915H, Alger, 45 stages, 11.6 million lbs, t2/17; cum --  

Early Use Of ESPs In The Bakken -- August 4, 2015

Again, a big thank you to the reader who recently alerted me to the early use of ESPs by EOG and Halcon. From today's daily activity report of wells coming off the confidential list:

• 28525, 1,227, EOG, Parshall 58-1608H, Parshall, ESP July 3, 2015; 43 stages, 9.1 million lbs sand, 7 million gallons xl gel, HCl, fresh water; t2/15; cum 83K 6/15;
• 28639, 848, EOG, Parshall 92-28H, Parshall, ESP February 21, 2015, 34 stages, 6.7 million lbs sand, 5 million gallons xl gel, HCl, fresh water, t2/15; cum 55K 6/15;

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Native North Dakota Grasses 

 

And for those curious about the mix of grass that EOG uses in reclaiming land:

• Western Wheatgrass, 41.35%
• Green Needle Grass, 20.46%
• Slender Wheatgrass, 25,88%
• Side Oats Grama, 10.60%

I wonder what Greenpeace and/or the Sierra Club use / recommend?

Not Ready For Prime-Time

This post will be up for a few minutes, and then it will be taken down. It will be up long enough for a link, and then taken down. It will be re-posted sometime in the future.

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The Sky Is Falling

I'm getting a number of e-mails (more than ever before) suggesting that the US government needs to get involved.

My answer:

I don't think Saudi is going to continue giving their oil away for $50 to $60 for very long.

Saudi put themselves in a real bind.

They did this back in the 80's, I believe (I often get my history wrong) to destroy the surging US oil boom (Alaska?, I forget), and they were successful short term. They are trying it again.

I don't think they realized that oil would fall this fast and this far.

Tight oil economics is not like Alaska oil economics. Unlike the 80's, they are competing with a tsunami of US shale oil that can easily be scaled back until prices come back. And prices don't have to come back very far. Even at $75 the Bakken will do fine.

So, back to the thesis: Saudi has put themselves in a real bind: a) they are now losing $138 million / day quibbling over 640,000 bopd (Fitzsimmons said that, I believe). They have huge cash reserves, but even so, $138 million per day is not bird feed; b) the Saudi sheiks are invested in the market as much as any American (don't they practically own Citibank?), and they are seeing their equity portfolios dive in value also; c) they probably invest in what they know and they are probably overweighted in oil and oil service companies, which are plunging in share value, and, d) they are giving away their grandchildren's inheritance (they've said that many, many times).

On the other side of the coin, if they even hint at holding another meeting before the end of January, 2015, they will be seen as blinking; losing "face" in the Mideast is about as bad as losing a war.

So, they can suck up a loss of $138 million/day in lost oil revenue; see their oil and gas equity portfolios dive; or lose face. If, as the OPEC oil chief is saying that supply and demand fundamentals do not lead to $60 oil and he thinks "speculators" are driving down the price of oil, the big question is how high will those same "speculators" drive the price of oil if Saudi cuts (or even hints they will cut) production.

I might be whistling past the graveyard, but at the end of the day, free market capitalism tends to sort these things out.

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Wells Waiting To Be Completed Are Increasing In Number

Director's Cut, December, 2014 -- October, 2014, Data

Slump in oil prices, Well Completions, December 13, 2014:

I've said many, many times on the blog: this is all about liquidity now, not profitability. The companies that can keep drilling, minimize production, maintain cash flow and/or liquidity, can drill wells, and delay completions.

From what I can see, early in the Bakken, drilling to TD / fracking was 50-50 proposition. But wells are getting to TD much more quickly, and with the cut back in drilling, the day-rate for rigs will drop, drillers will save huge amounts of money drilling to TD (man-hours, day rates on rigs, daily costs to BHI, SLB for wirelog, consulting geologists).

On the other hand, the fracking is getting much more expensive: a) huge amounts of sand; b) more sophisticated fracking with more stages; c) more ceramic for those who use ceramic.

I doubt the drilling to TD / fracking is 50-50 any more. I'm sure the numbers are easy to find, but I don't have the time and one might need Premium Services, which I don't have, to get the data over at NDIC.

If one includes leases, exploration costs, etc, as part of the overall cost of drilling to TD (and not part of fracking) -- to compare drilling tight wells with conventional wells, then the overall cost of drilling to TD in the Bakken has gone way done. Exploration costs and outrageous leasing is a thing of the past.

It really is interesting (based on the Bloomberg Businessweek article): shale operators are so flexible, they could drill the wells all winter while the price of oil is $40/bbl in the Bakken, but not complete any of the wells. Then, if oil moves toward $70 next summer, they frack the wells; the front-end is where they get huge production.

Random Note From Halcon On Decline Rates In The Bakken; Staggering

During the Q&A period of the conference call, a question was asked about the decline rates in the Bakken. The analyst noted that "everyone" in the Bakken is improving production because operators are learning more and more about completion techniques. The analyst asked when Halcon would be sharing their new graphs with updated decline rates. Here was Halcon's answer:

The improvements have been coming so fast and furious, we really can't keep up with it.

We tend to not put out updated type curves until we have significant history on a well. So certainly, some time over the next couple of quarters. But that field [the Fort Berthold area in North Dakota], as you know, has been so drilled in every area that you need type curves in every area. And for our company, we probably have about 6 or 7 type curves.

But then we'd have to start looking at type curves with slickwater fracs and without slickwater fracs, and type curves where you have tight spacing and type curves where you don't have tight spacing.

What I can say is that the initial wave of completion design modifications that we've done from the north end of the field doubled our IPs and our 30-day rates, and down the south end, increased them by 30% to 50%.

That should yield a much higher type curve, but we're just not prepared to put those out there. You can take our old type curves and just assume that the new ones will be higher.

Music to my ears. We've been blogging that since the beginning. 

Earlier in the presentation, this is what Floyd Wilson, the CEO, had to say:

All current wells are dramatically outperforming well drilling completed using previous methods and drilled by previous operators. Most of all -- most all of our 2014 wells will be drilled from pads. Cost reductions should continue.

At Fort Berthold, and this is really important news to us, that Fort Berthold downspacing results have been positive -- early but positive. Three (3) middle Bakken wells drilled on 660-foot spacing came in at nearly 2,700 barrels of oil equivalent per day average per well. And after several weeks, those wells are holding up as expected, with that IP rate as a start.

At another site at Fort Berthold, we set a new company record IP rate of over 3,900 barrel of oil equivalent per day.

At South Fort Berthold, our first slickwater fracs were a significant improvement over nearby wells on a 60-day rate basis. They were nearly 60% better than the nearby wells over the first 60 days.

At North Fort Berthold, our first slickwater-frac-ed well was a 30% improvement over nearby wells.

So this slickwater technique and this concentration of proppant and more complex fracturing, which is our target and others' targets here, seems to be working.

The downspacing issues in the Williston basin could be really important for our company and others. Our total location inventory in the basin could be nearly 1,000 if middle Bakken and Three Forks downspacing testing continues to be fruitful.