Red River Water Project -- Update -- August 22, 2021

We first mentioned this project on the blog on August 6, 2021, thanks to an alert from Geoff Simon. 

In the 11+ years I've been blogging, I've never read an article on a drought in eastern North Dakota, whereas the western third of the state seems to be in a perpetual and never-ending drought.

From a reader today:

From a reader: 

I am inherently suspicious of this kind of project.

I really don't like taking water out of the southern-draining Missouri and rerouting it to drain into Hudson Bay

I really, really don't like it because it gives the eastern part of the state a reason to be interested in how much water we use to frack.

I suspect that rather than prepare for a rare drought, what they really want to do is pump flood water the other direction.  Many more floods in the Red River than droughts.  Of course, it costs money to pump water uphill.

https://www.grandforksherald.com/news/government-and-politics/7138672-Crews-break-ground-on-pipeline-to-supply-water-to-Red-River-Valley-during-droughts

Water -- Fracking Vs Putting Out A Tesla Plaid Fire -- July 12, 2021

20 tons of water = 128 bbls of water = 5,376 gallons of water. 

From ZeroHedge, 20 to 75 tons to put out a Tesla Plaid fire, a steady stream for ninety minutes.

ICE single vehicle fire? three tons.

A single frack:

• 41,586 bbls of water (#27313, Hess EN-Eva).
• 217,831 bbls of water (#36000, Hess AN-Mogen Trust).

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Apple

Mac shipments continue to rise: from MacRumors. 

Shipments of Macs increased by almost 10 percent in the second quarter of 2021 compared to the same time last year, as the surge in demand for computers continued.

... worldwide shipments of personal computers, including desktops, notebooks, and workstations, reached 83.6 million units in the second quarter of 2021. This is an increase of 13.2 percent from the second quarter of 2020, in spite of component shortages across the industry that constrained supply. 

... but the rate of growth is slowing ...  Apple remained the fourth-largest PC vendor, tied with Acer, surpassed only by Lenovo, HP, and Dell, of which each had over double the number of shipments compared to Apple. 

Apple is set to hold its third quarter earnings call on July 27.

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Nicknames

According to sources, the Washington, DC, NFL football team has ruled out "Warriors" as a possible replacement for its previous nickname, the Redskins.

It is also noted that "Wallflowers" has not been ruled out. Nor has "Wimps." Or "Wafflers" [see first comment]. Bidin' their time until they come up with a suitable slate to consider.

Huge Notice Regarding MRO Fracks -- January 3, 2021

Last year I noted a number of MRO wells fracked with extremely small amounts of water, "by mass on a per cent basis." Tonight, some of the mystery is explained. I did not notice it until tonight.

In general, one can expect the amount of water used in a Bakken frack to be somewhere between 83% and 95% by mass. The most common range seems to be 88% to 93%.

Sometime last year I noted that the percentage of water used in some MRO completions was very low, around 55%. 

Tonight, I noted that those wells fracked with "55% water by mass" was more likely to be:

• 55% fresh water by mass; and, supplemented with
• 20% produced water by mass.

I'll go back and correct those wells with "low" amounts of water used to frack a well, but until I get that done (and I probably won't correct all of them) assume that any MRO well fracked with less than 71% water by mass, probably means that an additional amount of produced water, by about 20% supplemented the fresh water. 

It looks like the total amount of water used by MRO in this new (2020) completion strategy has not changed, but the "mix" has changed, to include a significant amount of produced water. 

So, the error is on me.

I'm just glad I caught it when I did.

Low Water Fracks -- Enerplus -- We've Seen This before -- November 19, 2020

We've seen this before:

• 35966, drl/A, Enerplus, Yellowstone 148-95-02B-11H, Eagle Nest, t--; cum 124K 9/20; a 27K month; 33-025-03655; fracked 3/9/20 - 3/21/20; 6.6 million gallons of water; 67% water by mass;
  
• 22574, drl/A, Enerplus, Glacier 148-95-02A-11H TF, Eagle Nest, t--; cum 117K 9/20; a 27K month; 33-025-01651; fracked 3/10/20 - 3/20/20; 6.5 million gallons of water; 67% water by mass;
  
• 35967, drl/A, Enerplus, Everglades 148-95-02A-11H-TF, Eagle Nest, t--; cum 105K 9/20; a 30K month; 33-025-03656; fracked 3/9/20 - 3/21/20; 7.5 million gallons of water; 68%% water by mass; 
  

From "completion strategies, 2020":

Enerplus:

6 - 8 million gallons of water; 65% water by mass; link here; "National Park" wells in Eagle Nest oil field;

Produced Water -- BR -- October 6, 2020

This phenomenon was brought to my attention by a reader about a year ago, maybe two years ago. Time flies when having fun.

The well:

• 34058, 541, BR, Kermit 8-8-32MBH, Pershing, t8/18; cum 241K 8/20; fracked 7/1/19 7/9/19; 7.1 million gallons of water; 87.7% water by mass;

Look at the rate of produced water in this well (see this post): 

BR pumped 169,000 bbls of water down this well for fracking. Look how slowly BR allowed "produced water" to return to the surface. This is simply incredible. After the frack:

• month 1: 7K bbls
• month: 2: 10K
• month 3: 7K
• month 4: 6K
• month 5: 5K
  
• month 6: --
• month 7: --
• month 8: 3K
• month 9: 9K
• month 10: 2K
• month: 11: 5K
• month 12: 0K

Compared to what I'm seeing by most operators, this is absolutely incredible.

An unintended (positive) consequence: a lot less "craziness" with regard to taking all that produced water away in the first six months; BR "flattens that curve" over two years. 

Fracking: Errors In Reporting, Anomalies, Testing? -- August 12, 2020

We now have two interesting situations. 

In the first case, posted some time ago, FracFocus suggesting no sand was used in fracking these two wells (which I highly doubt):

• #34601, $34602 -- no sand in these two fracks?

And now, three wells in which the water by mass was only 60%. Normally, water by mass ranges from 88% to 92%:

• 35600, SI/NC, Enerplus, Alto 149-94-33C-28H-TF, Eagle Nest, t--; cum 124K 6/20; did not shut down; however, only 24 days in 6/20; a 28K month; from Fracfocus: 5.6 million gallons of water, moderate (almost small) frack; fourteen days to frack; water: 59.99% by mass; if that's accurate, that's remarkable; generally, water by mass runs 87% to 92%;
• 35599, SI/NC, Enerplus, Haze 149-94-33C-28H-TF, Eagle Nest, t--; cum 141K 6/20; did not shut down; 29 days in 6/20; a 34K month; from Fracfocus: 8.3 million gallons of water, moderately large frack; fourteen days to frack; water: 60.57% by mass; if that's accurate, that's remarkable; generally, water by mass runs 87% to 92%;
• 35598, SI/NC, Enerplus, Vapor 149-94-33C-28H-TF, Eagle Nest, t--; cum 93K 6/20; did not shut down, but only 10 days in 6/20; a 33K month; from Fracfocus: 8.5 million gallons of water, moderately large frack; fourteen days to frack; water: 60.66% by mass; if that's accurate, that's remarkable; generally, water by mass runs 87% to 92%;

Incredible Wells Still Being Reported In The Bakken -- Note Small Amount Of Fracking Water Used By Enerplus -- August 12, 2020

Say what you want, these are incredible wells.

 Disclaimer: I am inappropriately exuberant about the Bakken.

When looking at these numbers I am reminded of Oasis' decision to focus on the Permian rather than the Bakken, using the Bakken to provide necessary cash flow for Bakken operations. The decision was made when the Permian was all the range, acquisition costs were incredibly high, and shortly before Covid-19 and Saudi's decision to flood the world with oil for the second time in just a few years

These are the wells coming off the confidential list today.

 Wednesday, August 12, 2020: 40 for the month; 111 for the quarter, 557 for the year:

• 36981, drl/TAI, CLR, LCU Truman 7-23H, Long Creek, no production data,
  
• 36744, drl/NC, XTO, FBIR Lawrence 24X-26A, Heart Butte, no production data,
  
• 36421, SI/A, Zavanna, Panther 16-21 2TFH, Stony Creek, t--; cum 107K 6/20; did not shut down during 5/20;
  
• 36350, drl/A, Hess, EN-Thompson Trust-154-94-1930H-5, Alkali Creek, t--; cum 117K 6/20; did not shut down during 5/20; a 31K month;
  
• 36159, drl/A, Hess, GO-Hauge-156-97-2116H-3, Dollar Joe, t--; cum 84K 6/20; shut in, 6/20; did not shut in during 5/20;
  
• 35721, SI/A, Oasis, A. Johnson 5298 11-1 4B, Banks, t--; cum 121K 6/20; was not shut in; a 30K month;
  
• 35600, SI/NC, Enerplus, Alto 149-94-33C-28H-TF, Eagle Nest, t--; cum 124K 6/20; did not shut down; however, only 24 days in 6/20; a 28K month; from Fracfocus: 5.6 million gallons of water, moderate (almost small) frack; fourteen days to frack; water: 59.99% by mass; if that's accurate, that's remarkable; generally, water by mass runs 87% to 92%;
• 35599, SI/NC, Enerplus, Haze 149-94-33C-28H-TF, Eagle Nest, t--; cum 141K 6/20; did not shut down; 29 days in 6/20; a 34K month; from Fracfocus: 8.3 million gallons of water, moderately large frack; fourteen days to frack; water: 60.57% by mass; if that's accurate, that's remarkable; generally, water by mass runs 87% to 92%;
• 35598, SI/NC, Enerplus, Vapor 149-94-33C-28H-TF, Eagle Nest, t--; cum 93K 6/20; did not shut down, but only 10 days in 6/20; a 33K month; from Fracfocus: 8.5 million gallons of water, moderately large frack; fourteen days to frack; water: 60.66% by mass; if that's accurate, that's remarkable; generally, water by mass runs 87% to 92%;
  

*********************************************
Enerplus: Early Production Data

Note production for the Enerplus Haze well, #35600:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	6-2020	24	19095	19081	19978	25267	23941	573
BAKKEN	5-2020	31	28191	28273	30030	33007	31120	846
BAKKEN	4-2020	30	26230	26053	28003	28554	27340	787
BAKKEN	3-2020	30	27878	28149	32299	27878	26911	851
BAKKEN	2-2020	17	22956	22507	40635	22957	20502	2348

Note production for the Enerplus Haze well, #35599:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	6-2020	29	28117	27921	19645	37033	35033	844
BAKKEN	5-2020	26	22909	23027	16576	26832	25345	687
BAKKEN	4-2020	29	25084	24963	17378	27352	26196	753
BAKKEN	3-2020	30	34055	34435	24470	34083	32921	1022
BAKKEN	2-2020	17	30544	29946	33884	30544	27278	3122

Note production for the Enerplus Haze well, #35598:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	6-2020	10	8767	8764	10459	11550	10997	263
BAKKEN	5-2020	19	13203	13356	20039	15514	14701	396
BAKKEN	4-2020	30	20728	20654	28801	22634	21674	622
BAKKEN	3-2020	29	32590	32733	36652	32590	31293	1168
BAKKEN	2-2020	17	17927	17576	36742	17927	16011	1831

"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. 

Something New In The Bakken? EOG, Fracking, Water Percentage By Mass, Sand -- March 8, 2020

Something new in the Bakken?

It begins at this link, posted a few days ago. It's a long, long note, interrupted by screenshots of data from FracFocus. I've added the notes a reader sent me almost immediately after posting that note. I delayed posting the reader's note until I had a chance to do some background reading.

Now, hold that thought -- the staggering production of that EOG well; the staggering amount of water used; and, the relatively large amount of sand -- relative to water by mass (percentage).

Now, go to these three EOG wells that will come off the confidential list this week. In two of the cases we have FracFocus data. Note again, the relative large amount of sand compared to the amount of water by mass. Generally I expect 87% to 93% water by mass in the FracFocus data but in this case, FracFocus reports 81% water by mass in one case; and, 83% water by mass in the second case.

FracFocus did not have data for the third well.

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

Other Wells Of Interest

Completely unrelated to the note above, two wells have been added to the index of wells of interest:

• 28747, Clarks Creek, Slawson, Jore Federal; jump in production; 
• 17421, Union Center, BR, several Midnight Run wells off line without explanation, 1/20; 

It really is not much benefit looking at these wells. I do this for my benefit to remind myself to check back on these wells later. 

The Myth That Daughter Wells Don't Come In As Good As Parent Wells -- EOG Experience In Clarks Creek -- March 8, 2020

These wells have recently come off the confidential list. The scout ticket information is complete but the file reports have not been updated; still confidential. The only frack data we have is that provided by FracFocus.

Graphics pending, but Clarks Creek has been covered frequently and extensively on the blog. The Clarks Creek oil field is tracked here. Years ago I summarized this oil field as such:

Clarks Creek: sweet spot in the Bakken; western boundary of the reservation; "owned" by EOG; will put 22 wells on one 2560-acre spacing unit (April, 2013, dockets)

The wells:

• 36416, 2,859, EOG, Clarks Creek 105-0719H, 33-053-09061, Clarks Creek, fracked, 7/20/19 - 8/22/19; 11.5 million gallons of water; 83% water by mass; hydrotreated distillate, 0.05147;

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	1-2020	31	23708	23654	16684	63891	59801	2060
BAKKEN	12-2019	31	30805	30839	20042	50132	42916	4647
BAKKEN	11-2019	27	39485	39737	29383	95185	92288	2621
BAKKEN	10-2019	31	71790	71611	46157	105252	96448	8764
BAKKEN	9-2019	24	67207	66951	40123	97464	87763	6335

• 36415, 3,519, EOG, Clarks Creek 18-0719H, 33-053-09060, Clarks Creek, no data at FracFocus yet;

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	1-2020	31	25241	25209	21206	69626	64134	2209
BAKKEN	12-2019	31	38081	38121	27255	90559	78940	8548
BAKKEN	11-2019	29	48272	48555	36103	83496	79616	2258
BAKKEN	10-2019	31	83639	83464	55098	103234	93516	8480
BAKKEN	9-2019	24	87186	86854	49463	116643	104174	7502

• 36413, 2,058, EOG, Clarks Creek 106-0724H, 33-053-09058, Clarks Creek, 1920-acre spacing, fracked 7/25/19 - 8/23/19; 11.4 million gallons of water; 81.1% water by mass; hydrotreated distillate, 0.05161;

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	1-2020	29	29256	29233	17267	59618	59196	0
BAKKEN	12-2019	31	60158	60322	28418	172686	172190	0
BAKKEN	11-2019	30	73884	73804	31665	126112	122169	3465
BAKKEN	10-2019	31	75609	75855	33217	98248	89623	8132
BAKKEN	9-2019	24	52481	51832	25099	74168	68307	4930

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.

"California's EV Dream Is Turning Into A Nightmare" -- Oilprice -- October 23, 2019

Is there a new sheriff in town? I never expected to see this headline over at oilprice.com: "California's electric vehicle dream is turning into a nightmare." Link here.

California might be blazing a trail with getting a large number of electric vehicles on the road, but the only trail California is currently blazing is the wildfire/PG&E fiasco that could once again plunge millions of Californians into the dark in the next wave of blackouts, expected today, the likes of which could sour investor confidence in purchasing a vehicle that relies on sketchy power sources.

 It’s windy in dry California, and apparently that’s enough to trigger another preemptive blackout for PG&E customers. For starters, PG&E will cut power to 179,000 residents on Wednesday.

But it’s not just PG&E. Other utilities, too, such as Edison International and Sempra, are also expected to cut off power to hundreds of thousands of Californians who are in an area that is notoriously dry, with winds expected to combine with those dry conditions to create too much of a fire risk.

Meanwhile, Governor Newsom has asked for an investigation into the high price of gasoline in his state of California.  As lieutenant governor, Newsom supported higher gasoline taxes and the public went along with him, voting to raise taxes on gasoline.

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

Water, Coal, and Fracking

Golf courses are not mentioned. We've discussed this before.

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.

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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.

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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.

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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.

April 19, 2019 -- Back To The Bakken

A problem the Bakken does not have: water.

The Permian. "The largest challenge to Permian field development. -- Rigzone. Data points:

• this is all about disposal
• even with 100 percent water re-use for completions, which is unlikely, the current salt water disposal infrastructure is expected to hit capacity in the near future
• trucking a major traffic problem in west Texas
• water disposal costs can account for a third of total lease operating expenses in the Permian
• water midstream space is “ripe” for mergers and acquisitions and revealed that it expects the pace of water-related infrastructure deals in the Permian to “pick up considerably” in 2019

That's disposal. What about frack water?

Back in January, Rystad Energy revealed that demand for frac water in the Permian exceeded the total U.S. demand of 2016. The company forecasted at the time that water demand in the Permian will likely surpass 2.5 billion barrels by 2020.

I've lost the bubble on this one, but I believe operators use four to five times the amount of sand to frack a well in the Permian compared to that used in the Bakken, and a corresponding increase in sand requires a corresponding increase in water.

Marathon has cracked the code on using less sand (and thus less water) in the Bakken.

By the way, no mention of earthquakes.

What We Do On The Weekends When Not Blogging About The Bakken;  video by Sophia, Ft Worth Stockyards (Texas)

We've Been Through This Before -- The Bakken Has Plenty Of Water. The Permian? No Problem -- Rigzone -- January 22, 2019

From Rigzone: frack water demand in the US skyrockets.

While U.S. shale oil production is hitting record levels, Rystad has found that frac water demand has more than doubled since 2016. The demand in the Permian alone currently exceeds all of U.S. demand of 2016.

The future for frack water demand also looks positive, with Rystad predicting demand to grow by an additional 6 percent in 2019 [inconsequential]. The Permian will see demand surpass 2.5 billion barrels by 2020.

"Even with such steep growth, market concerns about sourcing challenges and bottlenecks appear to be minimal.”

Rystad noted strong growth for the water treatment market in 2018, with a 28 percent expansion to 1.4 billion barrels last year. The market is forecast to double 2016 totals by 2020.

Note: the amount of water used in the Bakken has remained relatively stable for several years.

Missouri River Continues To Rise; Additional Water Will Be Released At Garrison Dam -- June 18, 2018

This is an update from an earlier post. From The Bixmarck Tribune:

The Missouri River will rise another foot and a half near Bismarck this week as the U.S. Army Corps of Engineers again steps up releases from the Garrison Dam, which is cresting 7.25 feet below 2011 flood levels.

Water released will go from 44,000 cubic feet per second to 52,000 cfs over the next three days, reaching the 52,000 cfs rate on Wednesday and continuing at this rate into early July. That is equal to 388,987 gallons per second. The increase is due to continued rapid snowpack melt and rainfall runoff.

Now for some fun.

We've done this before.

Conversion:

• one cubic foot of water = 7.48 gallons
• 50,000 cubic feet of water = 374,000 gallons
• the USACOE will release 374,000 gallons of water every second starting in two days and going into early July -- let's say, maybe a month of an increased rate
• but I digress
• in one second: 374,000 gallons of water
• one minute: 22 million gallons of water (enough water to frack two Bakken wells)
• one hour: sixty times that much or enough water to frack 120 Bakken wells
• one day: 24 x 120 Bakken wells = 2,880 Bakken wells
• the oil industry will probably frack about 1,500 Bakken wells this year

I remember when folks worried whether there would be enough water in North Dakota to frack all those wells. 

Disclaimer: I often make simple arithmetic errors, and I often round numbers.

Venezuela Story Updated -- June 5, 2018

At this link.

I think this is going to be a huge story. It may be bigger than the Greek story (near default) some years ago; bigger than the recent Italian story. There are so many story lines. It will be interesting to see how this plays out. If the NY Times fails to cover this story in detail, it's letting its readers down.

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Fun in the Sun

Updates

June 18, 2018: see update here.

Original Post

From The Bismarck Tribune: Lake Sakakawea levels expected to peak in coming week.

The lake is forecasted to continue its rise through next week, rising another 3.5 feet to peak near an elevation of 1,851.5 feet, according to the U.S. Army Corps of Engineers' June 5 outlook. The lake rose 4.3 feet during the month of May to its current level of 1,848.1 feet, about a foot higher than what was expected.

Two things: more than enough water in North Dakota for fracking. One can track Garrison Dam release rate at this link, but unfortunately, one day at a time, and will download as a pdf.

• Garrison Dam water release

Weather.gov has river elevation at the Garrison Dam on a daily basis.

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Cognitive Dissonance

As regular readers of the blog know, the "blogger.app" owned by Google won't allow links to Fox news outlets. Now this:

What Will Permian Operators Do With All That Produced Water? -- RBN Energy -- June 12, 2017

RBN Energy: what are "we" going to do with all that produced water?

Today most produced water moves off the lease in trucks, although producers are now increasing their investment in produced water-gathering and transportation systems to move the barrels to centralized facilities and disposal wells. But here’s the bottom line: it costs just about as much to move a barrel of water as it costs to move a barrel of oil.

And there is a lot more water than oil coming from a given well. The implication is that the largest single cost of operating a well — sometimes more than half of total operating cost — is produced-water disposal. That is a number that can impact producer economics and thus capex investment plans, drilling activity and production growth.

Worse yet, there is concern in some quarters that the sheer volume of produced water may eventually overwhelm the ability of the network of facilities and disposal wells to keep up with crude oil production, resulting in a constraint on growth in the Permian. In the next blog in this series we will examine the costs of produced water disposal and how those costs may affect Permian crude oil development over the next few years.

Active rigs:

$46.05	6/12/2017	06/12/2016	06/12/2015	06/12/2014	06/12/2013
Active Rigs	52	28	76	185	187

Slawson's Torpedo Federal Wells -- March 24, 2017

The Wells

Twelve producing wells (DUCs) reported as completed:

• 31278, 4,862, Slawson, Torpedo Federal 10H, t12/18; cum 178K after 41 days; cum 574K 2/20; off line 2/20; see this post;
• 31277, 825, Slawson, Torpedo Federal 9H, t12/18; cum 238K 4/20; off line 3/20;
• 31276, 2,942, Slawson, Torpedo Federal 8H, t12/18; cum 323K 4/20; off line 3/20;
  
• 31275, 3,632, Slawson, Torpedo Federal 7H, t12/18; cum 304K 3/20; off line 3/20;
• 31274, 3,205, Slawson, Torpedo Federal 6H, t12/18; cum 24K after 19 days; cum 271K 3/20; off line 3/20;
• 31273, 2,254, Slawson, Torpedo Federal 5H, t12/18; cum 34K after 39 days; cum 218K 3/20; off line 4/20;
• 31272, 1,090, Slawson, Torpedo Federal 4H, t12/18; cum 35K after 37 days; cum 233K 4/20; off line 4/20;
• 31271, 1,109, Slawson, Torpedo Federal 3H, 33-061-03689, Big Bend, 10.8 million gallons of waer; 89% water, t12/18; cum 13K after 16 days; cum 208K 3/20; off line 3/20;
• 31270, 1,523, Slawson, Torpedo Federal 2H, 33-061-03688, Big Bend, no production data, fracked 9/7/2018 - 9/15/2018; 6.9 million gallons of water; 89% water; t12/18; cum 19K after 29days; cum 173K 3/20; off line 3/20;
• 31269, 1,857, Slawson, Torpedo Federal 1H, 33-061-03687, Big Bend, no production data, fracked 9/5/2018 - 9/12/2018; 5.9 million gallons; 89% water; t12/18; cum 18K after 27 days; cum 187K 3/20; off line 4/20;
• 31289, 1,794, Slawson, Bandit Federal 1 SLH, t12/18; cum 29K after 34 days; cum 271K 4/20; off line 4/20;
• 31279, 3,794, Slawson, Rebel Federal 1SLH, t12/18; cum 49K after 45 days; cum 426K 3/20; off line 3/20;
• 18924, 1,361, runs south, parallels #31289 which runs north; was off-line for a month, 9/18; back on line 10/18; t2/11; cum 551K 4/20; off line 4/20; subtle, perhaps, increase in production when it came back on line;
  

Updates

June 10, 2020: most of the Torpedo Federal wells are off line, probably due to low oil prices.  Updated graphic:

October 28, 2018: update. It appears that all eleven wells have now been drilled to depth; ten of the eleven wells are on SI/NC status; the eleventh is on drl status. Note: there are twelve wells on this pad, but #31289 runs north; whereas the other eleven run south under the river/lake.

November 15, 2017;  I can't imagine anyone being interested, but this is the link to the environmental impact study Slawson provided during the permitting process. It will open as a PDF, probably on your desktop.

April 1, 2017: The Bismarck Tribune has a story on this multi-well pad. 

March 25, 2017: this is pretty amazing if "we're" talking about the same wells. But that would not make sense. Yesterday I just happened to come across these Slawson permits/wells. I was just scanning the map and somehow happened upon these wells. Nothing more to the story. Then a few minutes ago, I was reading the Williston Wire. I had received it some days ago but didn't get to it until now. And there it was: an article on the BLM approving a permit for Slawson to drill the first eight of 11 wells from a single pad. But then again, the wells below have already been issued a permit from NDIC so I assume "we're" talking about different eleven (11) wells. From the linked article:

The Bureau of Land Management (BLM) has completed its environmental analysis on a proposal to drill oil wells on private land within the Fort Berthold Reservation near Lake Sakakawea. 

With completion of this environmental analysis, the BLM will approve a permit for the Slawson Exploration Company to drill the first eight of 11 wells from a single well pad.
The well pad will be located approximately 800 feet from the lake, with the production facilities located three quarters of a mile away. 

Although the well pad and facilities will be located on private land, the BLM must issue an approved permit to drill the Federally-managed leases, which will be accessed through horizontal drilling.

But it sure sounds like the same set of wells: the production facilities will be located three-quarters of a mile away, same as the site below in the "original post."

If these are the same wells, and it appears they are, this appears to be the process: the NDIC issues a permit, but if the BLM has jurisdiction, the BLM also has to approve the NDIC permit.

Original Post

From a sundry form received September 23, 2016:

Slawson requests that the referenced wells be removed from confidential status. Slawson will instead request confidential status upon completion as allowed per rule 43.02.03.31. Slawson estimates the drilling of these wells will commence in October, 2016, and last approximately 12 months. Our current plan is to drill the 10 Torpedo wells back-to-back before completion operations. Completion and clean out will last approximately 14 weeks. 

Some other notes from other correspondence:

• the wells are currently planned to be drilled with a rig equipped with a closed-loop mud system and electric motors, which eliminates reserve pits, and greatly reduces noise and emissions
• sound walls (32-feet in height) will be constructed and used during all drilling and completion activities
• completion operations will use a lay-flat pipeline system to deliver fresh water to the well site that will eliminate 600 trucks per day
• the production pad will be located offsite, approx one mile northeast
• pad location was moved north from originally proposed site to allow a greater distance from the lake ... the new location increased the overall length of each wellbore, added to the cost of each well by $250,000 for the 2-mile laterals and $400,000 for the three-mile laterals due to additional cement, tubulars, and drill days (approximately $4 million added project cost)

Proposed APD conditions allowing operation "only during the winter months will have" considerable operating and cost effects. It would also extend the complete drilling program to take 3 - 4 years instead of the 14-month timeframe described in the BLM Torpedo Federal Environmental Assessment.

Note: a water truck typically carries 11,600 gallons of water. A completion requiring 7,000,000 gallons of water translates to 7,000,000/ 11,600 = 600 trucks. [Update: see first comment -- in ND, there is a weight limit which translates to 8,000 gallons max for water. 8,000,000 gallons / 8,000 gallons = 1,000 trucks for a rather average frack.]
 
X marks the spot(s). Five sections in this drilling unit. 5 x 640 = 3200 acres, all under the lake:

The horizontals will run north to south and will fan out as seen in the graphics below:

Mix of lengths for the laterals:

Nice graphic of the area to include the town of Parshall: