16986 -- An Update -- January 16, 2025

Locator: 44695B.

Many years ago, probably in 2014, I placed a note to remind myself to check on this well at a later day. I followed up with another note to check again in December, 2023, because there was nothing to report. I completely forgot to check up on it in December, 2023, so I finally got around to checking it tonight. To say the least, it's confusing to me.

Here's the original post and the well:

May 6, 2021: EOG's application -- stripper well determination.

• 16986, INJP/1,347, EOG, Parshall 20-03H, s1/08; t 5/08; AL; cum 309K 1/22; short horizontal.
  

Gas injection, began in 2014:

• 16986, INJP/1,347, EOG, Parshall 20-03H, s1/08; t 5/08; AL; cum 275K 11/17; short horizontal. 

For quite some time, that well has been inactive. In 2023, the NDIC apparently wanted EOG to either abandon the well or start production, again.

There's a sundry form, dated April, 2024, that EOG was getting ready to put new wells on the pad.

Checking the pad tonight, the parent well:

• 16986, IA/INJP/1,347, EOG, Parshall 20-03H, s1/08; t 5/08; AL; cum 309K 1/22; short horizontal; minimal production in September, 2024, and then back off line, t5/08; cum 318K 9/24; now inactive;two new wells, both drl/A status:

The two new daughter wells:

• 39846, drl/A, EOG, Parshall 172-0312H, t8/23; cum 237K 11/24;

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	11-2024	30	10250	10176	5000	12799	12655	144
BAKKEN	10-2024	28	9832	9869	5372	10865	10796	69
BAKKEN	9-2024	27	9268	9216	4791	10509	10352	69
BAKKEN	8-2024	31	12127	12253	6252	11923	11732	90
BAKKEN	7-2024	31	13734	13758	6133	11951	11738	213
BAKKEN	6-2024	30	13924	13925	6142	11004	10809	195
BAKKEN	5-2024	31	14447	14515	6562	10241	10043	198
BAKKEN	4-2024	30	14618	14518	6654	9524	9326	198
BAKKEN	3-2024	30	12812	12733	6739	7486	7305	181
BAKKEN	2-2024	28	9769	9823	6697	5737	5678	59
BAKKEN	1-2024	31	12725	12739	4580	7550	7482	68
BAKKEN	12-2023	31	15306	15277	7369	8302	8240	62
BAKKEN	11-2023	30	16058	16163	9225	7833	7769	64
BAKKEN	10-2023	31	25626	25690	14002	12003	11905	98
BAKKEN	9-2023	30	30573	30479	24464	15611	15487	124
BAKKEN	8-2023	31	15658	15346	11426	7700	7644	56

• 39847, drl/A, EOG, Parshall 173-0312H, t8/23; cum 232K 11/24;

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	11-2024	30	8429	8389	7180	9375	9268	107
BAKKEN	10-2024	31	9747	9801	7880	10334	10272	62
BAKKEN	9-2024	30	9997	9918	8095	10071	10001	66
BAKKEN	8-2024	31	11321	11426	8643	9852	9772	75
BAKKEN	7-2024	31	12185	12215	9277	10510	10415	95
BAKKEN	6-2024	30	12752	12792	9542	9985	9900	85
BAKKEN	5-2024	31	15035	14940	10892	10548	10451	97
BAKKEN	4-2024	23	8812	8926	8470	5421	5365	56
BAKKEN	3-2024	31	15787	15854	12014	9313	9229	84
BAKKEN	2-2024	29	20128	20090	14654	11786	11699	87
BAKKEN	1-2024	31	18683	18666	20117	11065	10985	80
BAKKEN	12-2023	31	20325	20281	25313	11010	10942	68
BAKKEN	11-2023	30	20929	20909	25515	10196	10125	71
BAKKEN	10-2023	31	21660	21554	31180	10140	10063	77
BAKKEN	9-2023	21	13779	13850	22043	7342	7291	51
BAKKEN	8-2023	11	12757	12503	17739	6783	6741	42

The first thing I noticed, other than the fact these were nice wells, was the chronologic number of the two new wells but the parent well is still inactive despite the fact that the two new daughter wells have been producing since August, 2023. 

It looks like I will have to come back to the parent well and check it again in a few months.

Water Flooding -- Unremarkable -- October 11, 2023

Locator: 45729EOR.  

From 2012, water flooding EOR begins.

Results? Look incredibly unexciting. May be why we're not hearing much about water flooding in the Bakken.

"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. 

Pipelines, Pipelines, And More Pipelines -- December 22, 2019

Sent by an eagle-eyed reader. Thank you. 

Link here.

• PUC is considering to permit a pipeline
• CO2 pipeline
• 18 miles long; $9.2 million
• from Exxon Mobil's Shute Creek Gas Plant and COP's Lost Cabin Gas Plant in Wyoming
• via several pipelines to Fallon County in southeastern Montana
• from Fallon County through North Dakota through pipeline currently under consideration
• through Stark and Bowman counties
• Denbury Resources -- EOR project
• one other CO2 pipeline exists in the state
• authorized by the PSC in 1998
• CO2 from Basin Electric's Great Plains Synfuels Plant near Beulah to oil fields in Saskatchewan, Canada
• if approved, pipeline would be built in 2020; ready for injection in early 2021
• Cedar Creek Anticline Area: straddles North Dakota - Montana state line
• "secondary recovery" -- waterflooding
• "tertiary recovery" --  CO2

Also in the story:

The state Industrial Commission, which also regulates the oil industry, authorized a project in November that targets Bakken wells in Mountrail County. Hess is leading that effort, which involves injecting natural gas and a proprietary foam underground to build pressure and extract more oil.

One other enhanced oil recovery project secured approval from the Industrial Commission on Tuesday. XTO is proposing to inject natural gas into both the Bakken and Three Forks formations in Dunn County to boost oil production.

Answer To Pop Quiz -- August 5, 2019

Question: conventional wells or unconventional wells -- which have a higher ratio of produced water, conventional wells or unconventional wells? What is the ratio of produced water-to-oil in conventional wells compared to that of unconventional wells? [PWOR = produced water-to-oil water.]

The answer will be posted Monday, August 4, 2019, sometime during the day after I get caught up with the news that came out over the weekend.

Originally posted here, so some answers/replies will be at that post. 

On another note, 99.9999999%+ Americans can be thankful they had an uneventful weekend. Huge condolences to the families in Dayton, OH, and El Paso, TX.

Answer: conventional wells. And it's not even a close call. [Later, see this post also.]

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

Best Answer From A Reader

Your question regarding produced water is significant for several reasons. Conventional, vertical production may have 90 to 99 barrels of water for every single barrel of oil produced as a routine matter for older wells.

This is the single biggest expense in low producers and is the main determinant of when to permanently plug a well.

Unconventional in the Bakken is frequently in the 1 bbl water /1 bbl oil range which is pretty remarkable and a huge influence on the long term positive economic potential.

Water handling (for frac'ing in LTO, disposal in conventional and unconventional) is a big component in oil development operations.

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

Source From The Literature

This is what caught my attention and why I asked the question.

This is a screenshot of the abstract from an article published in 2017 with regard to the Permian.

The third sentence in that abstract: our results show that although conventional wells produce about 13 times more water than oil ... [a]lthough unconventional wells have a much lower PWOR of 3 versus 13 from conventional wells ...

This is the link to that article: https://pubs.acs.org/doi/10.1021/acs.est.7b02185. At the link you can download the pdf.

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

Produced Water Vs Flowback

A reader asked the question: what is the difference, if there is a difference, between produced water and flowback. The reader who best answered the original question, also provided this answer regarding produced water and flowback:

On whether flowback is same as produced water?

It is not, but I can not offer any legally/technically precise definition with which to precisely distinguish one from the other.

In the early Bakken years (probably Eagle Ford and Niobrara also), huge amounts of the frac fluid would be somewhat rapidly - within a few days' time - removed from the newly frac'd well. This was partially motivated in not wanting the formation to absorb the water, swell and inhibit production.

In the last 2 to 3 years, it is obvious that operators are maintaining VERY high quantities of frac water underground for SEVERAL months and the now-surfacing water is labelled as flowback. (The earlier years' rapid flowback was - to my knowledge - never officially recorded). This is why when the recent wells' production profiles show 200,000/250,000 barrels produced water first 5 months, purposeful underground retention is indicated.

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

For me, I apologize to readers. To some extent this was a "trick question." Everyone writing about fracking, including me, writes about the huge amount of water being used to frack the wells. So I was quite surprised to see how much water is actually used in conventional wells.

For me this was incredibly important: with the recent discussion of porosity and permeability, there were sidebar issues regarding water. If oil producers seem hassled by natural gas / flaring, I would imagine that issue pales in comparison to the problem they have with water.

Along with everything else about water in that linked PWOR study, there was a footnote in one of the replies to the porosity / permeability issue with regard to how Saudi Arabia almost "lost"one of their best fields due to water channeling.

So, I apologize for the trick question, but, wow, I sure learned a lot.

Bridger / Bonneville Wells Updated; Two Wells With Jump In Production; Not Re-Fracked -- December 21, 2017

Disclaimer: in a long note like this, there will be typographical and factual errors. If this information is important to you, go to the source.

Updates

December, 22, 2017: a reader noted I had the wrong production chart for one of the wells; that has been corrected. More important were his comments regarding these wells:

Original frac job required 660 days of production to produce 68,150 BBL of oil. In approximately 90 days (Aug, Sept, Oct) the well has produced 67,857.

FYI in November it produced 16,900 BBL. So in approx 126 days of production since refrac has produced 87,400. June-November.

Not bad for 4 months from a well that was put on production almost 9 years ago and had produced a total of 138,952 BBLs in that life  span if I am reading this correctly. [I've posted the full production history for this well at this post: note the production after the original frack and the huge amount of production after the re-frack.]

The reader asks:

So how much potential is out there with old wells that can be re-fracked? [A rhetorical question.]

The reader goes on:

The Bakken has a lot of negatives based on the northern climate work environment and the distance to markets compared to southern US Basins. But on the other hand it looks like the updated frac jobs are using a lot of water. And the Bakken is sitting in the middle of a large lake on the Missouri River. It will take some effort to put in an underground distribution system with pumping plants on the lake to provide water for frac jobs and water flood secondary production but I bet in the coming years we will see that.

Original Post

 

For newbies: this is an important post to help understand the the potential of the Bakken. I'm not going to go into it again but important concepts that are not being talked about by analysts with regard to the Bakken: total organic content (TOC); original oil in place (OOIP); multiple formations in the "Bakken": primary production; life history of Bakken wells that will produce for 30+ years (workovers; mini-re-fracks; neighboring fracks; re-fracks; microseismic arrays)

This well came off the confidential list today:

• 31845, 879, CLR, Bridger 7-14H2,Three Forks 2nd bench, t8/17; cum 52K 10/17;

Bridger/Bonneville wells have been updated.

Many updates, including name changes (change in formation targets) with the Bridger/Bonneville wells. Regardless of whether wells were re-fracked or not, the important point to note is that many older Bridger wells have had a significant jump in production.  

According to FracFocus this well was not re-fracked:

• 17088, 267, CLR, Bonneville 41-23H, Rattlesnake Point, t4/08; cum 160K 10/17;

Monthly Production Data for #17088:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	10-2017	17	3774	4049	1885	3599	247	3352
BAKKEN	9-2017	26	6780	6783	4591	4680	347	4333
BAKKEN	8-2017	31	11708	11926	12906	9448	9158	290
BAKKEN	7-2017	20	10614	10283	15486	8109	6652	1457
BAKKEN	6-2017	0	0	0	0	0	0	0
BAKKEN	5-2017	10	106	235	22	39	39	0
BAKKEN	4-2017	30	330	232	92	115	115	0
BAKKEN	3-2017	31	359	222	117	135	135	0

However, this well was re-fracked 4/17:

• 17089, 400, CLR, Bridger 44-14H, t4/08; cum 169K 8/17 and then back on confidential; re-fracked 4/17;

Monthly Production Data for #17089:

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

Likewise, this well showed a jump in production, but no evidence that it was re-fracked:

• 19012, 365, CLR, Bonneville 2-23H, Three Forks, 24 stages, 2.5 million lbs; 4 sections, t12/10; cum 171K 10/17; huge bump in production 6/17; not re-fracked according to FracFocus;

Monthly Production Data for #19012:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	10-2017	31	2460	2679	8162	2455	1798	657
BAKKEN	9-2017	29	1386	1054	5442	963	672	291
BAKKEN	8-2017	28	1269	1651	3584	758	482	276
BAKKEN	7-2017	31	8117	8055	12997	7612	6782	830
BAKKEN	6-2017	15	5477	5116	18058	5429	5290	139
BAKKEN	5-2017	19	434	526	277	400	391	9
BAKKEN	4-2017	30	886	1121	533	771	771	0
BAKKEN	3-2017	31	881	909	528	760	760	0
BAKKEN	2-2017	27	822	591	472	700	700	0
BAKKEN	1-2017	31	909	883	520	772	755	17
BAKKEN	12-2016	31	942	901	569	817	787	30
BAKKEN	11-2016	30	951	1151	548	876	852	24

Newburg Oil Field Where Enduro Has Permit For Water Injection, Enhanced Oil Recovery -- November 3, 2016

An area where Enduro will be using water injection for enhanced oil recovery. From today's daily activity report, this well has been permitted for water injection, enhanced oil recovery, see graphic below:

• 3440, loc/30, Enduro Operating, NSCU K-709, Newburg oil field, Spearfish/Charles pool, t10/63, cum 327K 2/08;

Comments regarding the renewed permit:

• it appears that #3440, was an old Spearfish/Charles well drilled back in 1963, and abandoned back in 2008; and is now going to be converted to a water injection well (an enhanced recovery well); the application was initially submitted in February, 2014;
• further reading
• how does water injection work - Rigzone
• injection wells, pdf - FracFocus
• old oil field waterflood operations and EOR, pdf -- New York state

This well is located in Newburg oil field, Spearfish/Charles pool, many of which are simple vertical wells. Many of them produced a fair amount of oil over the course of their life times.

Some are still active. For example, the index well in the graphic below, has produced more than one million bbls of oil is still active, and will celebrate its 60th anniversary next November, 2017:

• 1645, 30, Enduro Operating, Newburg-Spearfish-Charles Unit Q-715, Spearfish/Charles pool, t11/57; cum 1.14 million bbls 9/16; still producing about 250 bbls/month

I forgot to place an arrow designating the location of this field on the overview map of North Dakota, but if you look closely you can see a red "dot" near the Canadian border, in Bottineau County.

Another Example Of The Halo Effect In The Bakken -- And Just Think -- "We're" Only Getting Started -- June 12, 2016

Updates

June 13, 2016: a reader writes:

EOR (enhanced oil recovery) should have a good future in the Bakken. Water flooding should be great (water flooding is sometimes considered "primary recovery").

The least productive well on a pad, or a nearby pad would be used as a salt water reinjection well. It takes some horsepower to do this but the readily available "cheap" gas for the pumps should make it exceptionally profitable.

Original Post

 

This is going to be a long note. There will be typographical and factual errors. I may be seeing things that don't exist. I may be coming to conclusions that are incorrect. I am doing this to help me understand the Bakken and for no other reason. If this is important to you, go to the source. 

********************************** 

At the following monthly production spreadsheets, pay attention to the third column (the number of days the well was on-line in 11-2015 and 12-2015); the fourth column (bbls oil); and, the sixth column (bbls water):

Well #3 -- note the increase in water production noted in red --

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	4-2016	30	3636	3557	7336	4641	4551	0
BAKKEN	3-2016	31	3065	3250	10617	3867	3749	26
BAKKEN	2-2016	29	1888	1838	11169	2325	2204	35
BAKKEN	1-2016	30	2707	2658	15135	3860	2485	1285
BAKKEN	12-2015	13	1291	1322	6566	1975	0	1938
BAKKEN	11-2015	13	1126	1132	722	1109	0	1070
BAKKEN	10-2015	29	2681	2609	1579	3286	2346	858
BAKKEN	9-2015	30	2785	2953	1931	3655	3189	376
BAKKEN	8-2015	31	2966	3058	2837	4123	4001	29

Well #4 -- note: no increase in oil production, but look at the produced water in red:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	4-2016	30	6976	6797	6879	10897	10807	0
BAKKEN	3-2016	31	6656	6965	9752	11138	10410	635
BAKKEN	2-2016	29	5434	5357	12855	9725	9511	128
BAKKEN	1-2016	30	5699	5500	14309	8791	5518	3185
BAKKEN	12-2015	25	4979	5024	19680	7301	5694	1534
BAKKEN	11-2015	13	1450	1510	1070	2691	2399	253
BAKKEN	10-2015	31	3533	3446	2296	6262	6032	143
BAKKEN	9-2015	30	3444	3645	2431	5867	5240	537
BAKKEN	8-2015	31	3782	3859	2429	7385	7231	61

Well #1: no increase in either water or oil -- this well will turn out to be the farthest from the other wells; this well was not taken off-line during this period, unlike the other wells in this exercise:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	4-2016	30	2191	2116	2544	4085	3994	1
BAKKEN	3-2016	31	2359	2480	2761	4583	4464	26
BAKKEN	2-2016	29	2369	2408	2607	4936	4847	2
BAKKEN	1-2016	23	2581	2482	3287	4081	3985	30
BAKKEN	12-2015	31	2762	2877	3208	5571	4978	500
BAKKEN	11-2015	30	2704	2668	3000	4728	2868	1772
BAKKEN	10-2015	31	2674	2595	2890	3363	2764	507
BAKKEN	9-2015	30	2525	2610	2753	2766	2296	387
BAKKEN	8-2015	31	2754	2696	3078	3242	3103	5

Well #2 -- this is the newest well; it has just been fracked and has just started producing --

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	4-2016	30	10048	9798	8851	13602	13048	468
BAKKEN	3-2016	31	20441	20892	17039	30042	29308	642
BAKKEN	2-2016	29	26883	26987	23702	44006	38007	5912
BAKKEN	1-2016	30	22404	22030	31750	34998	14952	19957
BAKKEN	12-2015	25	24622	24284	43010	36231	1428	34728

The "Index" well: this is the well that caught my attention. Why did oil production jump in January, 2016? And note the huge increase in water production at the same time. Where did that water come from? Look how much water was produced in just 19 days in December, 2015 -- not due to fracking this well. This well was fracked years ago.

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	4-2016	30	7097	6942	7967	8285	8093	103
BAKKEN	3-2016	31	8100	8456	10182	9529	9358	78
BAKKEN	2-2016	29	6776	6560	11517	8000	7459	454
BAKKEN	1-2016	30	6268	6319	21254	9237	4655	4496
BAKKEN	12-2015	19	3254	3144	22383	3827	49	3724
BAKKEN	11-2015	12	724	747	399	949	783	132
BAKKEN	10-2015	31	2196	2109	1057	2525	2291	141
BAKKEN	9-2015	30	1949	2095	1346	2334	1899	345
BAKKEN	8-2015	31	2105	2075	1299	2637	2410	135
BAKKEN	7-2015	31	2189	2173	971	2638	2422	123
BAKKEN	6-2015	30	2129	2136	1232	2691	2273	328
BAKKEN	5-2015	31	2333	2274	1275	3089	2680	317
BAKKEN	4-2015	30	2337	2300	1733	2810	2275	446
BAKKEN	3-2015	31	2420	2617	1621	3897	2260	1544
BAKKEN	2-2015	28	2125	2069	1245	4162	2047	2033
BAKKEN	1-2015	31	2498	2714	1668	4545	2359	2093

 *****************************

Observations:

Well #3:

• it appears the well was taken off line in mid-November, 2015, and placed back on line in mid-December, 2015
• when it came back on-line, there was no noticeable increase in oil production
• however, look at the huge increase in water, going from1,500 bbls in October to over 15,000 bbls in January, 2016

Well #4:

• it appears the well was taken off line in mid-November, 2015, and placed back on line in late-December, 2015
• when it came back on-line, there was a noticeable increase in oil production
• also, look at the huge increase in water, going from 2,000 bbls in October to almost 20,000 bbls in December, 2015, even though that well was on-line for less than a full month ("severe vomiting")

Well #1:

• unlike wells #3 and #4, this well was not taken off-line during this period of time
• during this period of time, there was no noticeable increase in oil production, month-over-month
• in addition, there was no evidence in any change in the amount of water produced

Well #2:

• this well was brought on-line in late December, 2015, after it was fracked earlier
• following the frack, huge oil production
• following the frack, huge water production

Index well:

• it appears the well was taken off line in mid-November, 2015, and placed back on line in mid-December, 2015
• when it came back on-line, there was a huge increase in oil production
• in addition, look at the huge increase in water, going from1,000 bbls in October to over 22,000 bbls in January, 2016

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

The "Index Well" was a middle Bakken well:

I called the "index well," the index well because it had the most noticeable increase in oil production after a neighboring well was fracked.

Wells #1 and #3 were Three Forks wells.

Wells #2 and #4 were middle Bakken wells.

Summary:
1. Well #2 was a middle Bakken well, fracked in late 2015.
2. Wells #1 and #3 were Three Forks wells and did not show any evidence of the "halo effect" based on increased oil production. In addition, there was no evidence of communication based on produced water between the middle Bakken well (#2) and the Three Forks well #1 -- these two wells are 0.84 mile apart. However, there was evidence of communication based on water production between the middle Bakken well (#2) and the Three Forks well (#3). Wells #2 and #3 are laterally separated by about 265 feet. I assume the vertical separation is less than 100 feet.
3. The middle Bakken "index well" was 0.3 mile from the newly fracked well.
4. The middle Bakken well #4 was less than 800 feet from the newly fracked well. 

The graphic:

I apologize for the confusing graphic. I've labeled the horizontals twice: once with the permit number and formation target; and, a second time with just a numeric label.

I labeled the horizontals, 1 through 4, left to right; perhaps I should have numbered them differently. 

Calling one of the wells an index well may be confusing, but I called it that because it showed a definite halo effect. Once I saw the jump in oil production, I then looked for the likely explanation. The only possibility was the fracking of the neighboring well, which I call #2.

These are the wells:

• 18758, 714, Whiting, 20711 Paulso 49 1H, Stockyard Creek, t4/11; cum 230K 4/16;
• 23112, 1,657, Whiting, P Bibler 154-99-1-5-8-16H3, a Thee Forks well, t5/13; cum 180K 4/16;
• 24196, 2,251, Whiting, P Evans 154-99-2-4-9-15H3, a Three Forks well t8/13; cum 165K 4/16;
• 24198, 2,282, Whiting, P Evans 154-99-2-4-9-16H, t8/13; cum 199K 4/16;
• 30850, 2,015, Whiting, Marty 31-4H, Stockyard Creek, t12/15; cum 104K 4/16; API 33-105-04003-00-00; frack start 12/7/15; frack end 12/7/15; 7.6 million gallons of water; white sand frack, 9% by weight of total frack components (Frac Focus; data here at Frac Focus; 40 stages, 6.6 million lbs; the sundry form says the well was stimulated 11/18/2015.