Selected Basins, Drilled, Completions, DUCs -- For The Archives -- March 15, 2021

From a reader, thank you very much.

For the archives.

Note: in the process of transcribing this data and re-formatting, errors may have occurred. If this is important to you, go to the source.

"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. 

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.”

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:

Correlating Well Completions WIth Production In The Bakken -- April 1, 2018

Looking at QEP's re-frack program it dawned on me that I quit tracking monthly well completions quite some time ago.

Back on June 19, 2015, this note from the Director's Cut (April 2015) data:

• Bakken price in May: $44.70 
• Fracklog: 925 (an increase of 45); I had thought it would have been closer to 1,000 
• Completions: 94 -- a very, very low number; many wells going to SI/NC status  
• To maintain production near 1.2 million bopd: 110 - 120 completions needed each month 
• Statewide flaring: 18%  
• That figure is from Lynn Helms, back in 2015: to maintain production near 1.2 million bopd, 110 - 120 completions need to be made each month.

Disclaimer: there may be typographical and factual errors in the data below, but they will be insignificant and won't affect the comments/observations.

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Daily Production By Month vs Well Completions in That Month

January, 2018

• 1.176 million bbls/day
• wells completed in January: 56

December, 2017

• 1.181 million bbls/day
• wells completed in December: 106

November, 2017

• 1.19 million bbls/day
• wells completed in November: 60

October, 2017

• 1.185 million bbls/day
• wells completed in October: 81

September, 2017

• 1.1 million bbls
• wells completed in September: 70

August, 2017

• 1.08 million bbls
• wells completed in August: 84

July, 2017

• 1.05 million bbls
• wells completed in July: 95

June, 2017

• 1.03 million bbls/day
• wells completed in June: 88

May, 2017

• 1.04 million bbls/day
• wells completed in May: 66

April, 2017

• 1.05 million bbls/day
• wells completed in April: 53

March, 2017

• 1.025 million bbls/day
• wells completed in March: 61

February, 2017

• 1.034 million bbls/day
• wells completed in February: 61

January, 2017

• 0.98 million bbls/day
• wells completed in January: 56

December, 2016

• 0.94 million bbls/day
• wells completed in December: 84

November, 2016

• 1.03million bbls/day
• wells completed in November: 84

October, 2016

• 1.04 million bbls/day
• wells completed in November: 46

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Observations / Comments

It appears that significantly less than 100 well completions are needed each month to maintain production at 1.2 million bbls/day in North Dakota. In October, 2016, with 46 well completions, production was slightly over 1 million bbls/day

Daily production correlates not at all (or very minimally) with the number of well completions in any given month (assuming the number of well completions is in the range of 50 to 100; and that assumption may not be necessary, either)

• October, 2016: 46 completions; production over 1 million bbls
• December, 2016, only two months later: 84 completions; production does not hit the one-million-bbl threshold 
• December, 2017: 106 completions and production did not vary much in the big scheme of things

The single most important metric not provided in the monthly Director's Cut that affects daily production: full re-fracks; even that data would, in isolation, not be particularly helpful -- see below

Other factors affecting daily production (seasonally adjusted):

• wells coming off-line when new wells are being fracked; wells coming back on-line when neighboring wells have been fracked (QEP noted this challenge in the Bakken; a challenge they say they won't see to the same extent in the Permian); 
• mini-re-fracks
• work-overs

Other factors affecting daily production

• weather events

Spot price of crude oil probably has little affect on number of well completions: CAPEX and drilling schedules are in place well in advance of actual well completions; same goes for fracking and re-fracking

Fracking and re-fracks in North Dakota must drive the CFO crazy, as mentioned above:

• wells coming off-line when new wells are being fracked; wells coming back on-line when neighboring wells have been fracked (QEP noted this challenge in the Bakken; a challenge they say they won't see to the same extent in the Permian);
• although the CFOs now have sophisticated formulas to estimate how much oil will be shut in and for how long; and, how much oil will come back on line once a new well is fracked / re-fracked, clearly the operators are significantly challenged in this arena -- QEP has certainly spent a lot of time looking at this issue based on their most recent earnings call
• with regard to how much oil will come back on line when a well is fracked or re-fracked, we are not talking about a single well; we are talking about all the offset wells that were shut in while a well was fracked/re-fracked
• I've seen offset wells shut in for less than 30 days and I've seen offset wells shut in for four months while a neighboring well is being fracked / re-fracked -- I thought that was simply the cost of doing business; apparently in the Permian, QEP has determined this is something

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?

I Was Wrong: Someone At NDIC On Vacation? -- July 24, 2015

See this post for background to this note:

July 24, 2015: I may have been wrong. Another writer suggests that the reason for this 28-well completion was because the NDIC has only one employee who can enter the data and he/she was on vacation, and when he/she returned, all the data was input. From the reader who caught this, something I missed:

Did you happen to see the "explanation" of why there weren't any completions for awhile and then 28 all on one day's report?

Apparently NDIC has only one employee who can enter the data?? And he was on vacation??? Really??!!

https://sayanythingblog.com/entry/a-funny-story-about-that-alleged-slowdown-in-north-dakota-well-completions/

I liked the comment at the end (f the commentator's source is as reliable as posted):

"From a direct energy insider source, a major Bakken player is actually adding rigs within the next few months. Fracking is going to begin picking up using a new method which cuts the frack cost in half. He thinks we will have another 6 months of status quo, and things will take off again.

"Not quite ever the break neck pace of two years ago, but back to comfortable levels. Boom is far from over."

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The Red Queen Hasn't Fallen Off Her Treadmill

From SayAnythingBlog:

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

US Economy

The forecast for US auto sales in July are really quite remarkable, not just the number but the type of vehicles being sold.

Folks in the showroom are being told that the days of crude oil shortages are over; cheap gasoline as far out into the future as one can see.

From SeekingAlpha: U.S. auto sales forecast to rise 2.6% in July Jul 24 2015.

Kelley Blue Book forecasts new car sales in the U.S. will increase 2.6% Y/Y in July to 1.47M units, led by a 13.4% jump in the compact SUV/crossover segment.

Forecasts by major manufacturers are posted below.

• General Motors: +0.7% Y/Y to 258K units, market share of 17.6%. 
• Ford: +0.8% to 214K, market share of 14.6%. 
• Fiat Chrysler Automobiles: +4.4% to 175K units, market share of 11.9%. 
• Toyota: -0.4% to 215K units, market share 14.6%. 
• Honda: +2.3% to 139K units, market share 9.5%. 
• Nissan: +4.6% to 127K units, market share 8.6%. 
• Hyundai/Kia: -0.3% to 119K, market share 8.1%. 
• Volkswagen: +5.1% to 52K, market share 3.5%.

I "get" Volkswagen, and I know Chrysler is having an incredible run with Jeep, but I don't know what is moving Nissan. Is it the Nissan Rogue? From US News:

The 2015 Nissan Rogue ranks 5 out of 27 Affordable Compact SUVs. This ranking is based on our analysis of published reviews and test drives of the Nissan Rogue, as well as reliability and safety data.

Meanwhile, it was announced that Mitsubishi will be closing its one factory in the United States.

ND Oil Well Completions Slow Sharply -- John Kemp, Reuters, July 22, 2015

Talk about amazing timing. This story was posted yesterday by Reuters:

LONDON, July 22 (Reuters) - No new well completion reports have been filed in North Dakota since July 10, the longest gap this year, according to daily activity records published by the state's Department of Mineral Resources (DMR).

Completions, rather than wells drilled, provide the best guide to short-term changes in output, since operators can always delay completing a well and putting it into production, either because they are waiting for completion crews to be available or to wait for better prices.

Completion is usually defined as a single operation including the stimulation and testing of a well as well as the installation of surface production equipment ("Dictionary of petroleum exploration, drilling and production" 2014). North Dakota's regulators consider a well completed when the first oil is produced through wellhead equipment into tanks from the ultimate producing interval and after the well has been cased.

Well operators must file a completion report with state regulators within 30 days of the completion date, and in some circumstances immediately (https://www.dmr.nd.gov/oilgas/rules/forms/form6.PDF).

"In no case shall oil or gas be transported from the lease prior to the filing of a completion report unless approved by the (DMR) director," according to state rules.

Okay, so that was posted yesterday. It was probably written during the past couple of days by John Kemp while he was putting the data together and last edited his final draft on July 20th or July 21st.

Then this, yesterday:

The NDIC reported a record number of well completions in one day: 28 well completions reported yesterday.

I cannot verify that is a record but based on what I know about the Bakken, it appears to be a record. 

There is another data point that I did not mention from that same NDIC report yesterday: the number of wells that were reported as "producing or plugged."

I don't post that data, "producing or plugged" wells from the daily activity report, mostly because it does not add much to my knowledge base of the Bakken. It is interesting for mineral rights owners of individual wells but in the aggregate the data does not help me better understand the Bakken, the purpose of this blog. I reported years ago when first blogging that 99% of all "producing or plugged wells would eventually be shown to be "producing." I waited until the IPs were reported to post the new wells.

However, a reader yesterday noted that there was a fairly large number of "producing or plugged" wells on the daily activity report that also showed the 28 completions. There were nine (9), including Hess, Oasis (with 5 of the 9), BR, and EOG.

Remember, a few data points:

• for the past two months, the NDIC has reported 925 wells waiting for completion
• operators are drilling about 100 new wells/month, I suppose (based on 70 active rigs)
• the number of permits on a monthly basis is holding steady, perhaps creeping up slightly
• operators are expected to complete wells within one year of spudding
• winter is just around the corner.

One NDIC report does not a Bakken summer make, so it will be interesting to see whether the number of completions reported in one day was a one-off (an anomaly) or whether John Kemp had the misfortune of posting a great article that was out of date the very day it was posted.

By the way, look at this story that was just posted the other day suggesting shale well completions were rising, once again. 

Whiting Reports Two More Incredible Tarpon Federal Wells; Note The Number Of Stages-- July 23, 2015

I track Whiting's Tarpon wells here.

• 28495, 3,606, Whiting, Tarpon Federal 24-20-2RH, Sand Creek, 90 stages, 3.5 million lbs, t1/15; cum 70K 5/15; choked back;
• 28496, 2,959, Whiting, Tarpon Federal 24-20-3RTF, Sand Creek, 62 stages, 2.5 million lbs, t1/15; cum 55K 5/15; choked back;

Interesting completion: 90 stages and 62 stages, respectively, and yet a very, very modest amount of proppant.

Location of the Tarpon Federal wells posted here.

North Dakota Wells Must Be Drilled/Completed Within A Year -- RBN Energy -- April 10, 2015; Also, Reason For Backlog Of Wells Waiting To Be Fracked

Updates

November 24, 2015: a reminder -- the NDIC relaxed the one-year rule on well completions. Back on October 22, 2015, it was announced that the NDIC had given operators an extra year to complete wells. 
 

Original Post

 

From RBN Energy:

The prospect of the large trigger tax incentive kicking in on June 1, 2015 is one factor that might explain a recent increase in the number of wells that have been drilled and are awaiting completion in North Dakota (the State defines completion to mean when the first oil is produced through wellhead equipment into tanks).

[At the linked article] the chart in Figure #2 shows well completion data from the NDIC. The red line shows that the number of wells waiting on completion increased from just over 400 in January 2013 to more than 800 in January 2015.  

No doubt that some of these wells have been held up because producers are waiting to complete their wells when the large trigger tax incentive kicks in during June.  

But there is more to it than that. 

Wells can be waiting on completion for a number of other reasons.  These include the absence of infrastructure – as could be the case for North Dakota producers trying to comply with regulations to reduce flaring or needing to set up equipment to condition their crude for rail loading. In a low price environment, producers can also delay well completions as a form of storage – waiting for crude prices to recover. In North Dakota winter weather can also be reason enough to delay completions. The blue line in Figure #2 is the number of completions each month since January 2013 and although there were just 47 completions in January 2015 compared to 183 in December 2014, the numbers do not appear to be outside the normal range so some portion of the lower number of completions in January is likely just usual impact of the North Dakota winter.  

Generally speaking, smaller producers are incented to complete wells sooner rather than later in order to generate cash to repay finance costs so that lengthy completion delays are not common.

In any case, North Dakota drilling permits only last for a year – by which time producers have to drill and complete their wells - meaning that any backlog will only last for a limited time.

Fact-Checking: Completion Deadlines? -- April 8, 2015

Back on March 15, 2015, I said that North Dakota requires that wells be completed within a year of being drilled. I did not provide a source but I recall vividly having read that somewhere. A reader has called me on that -- if I had a source for that.

I think my source was a good source, but for all I know it was a comment made by a reader who has a friend who has a sister whose husband works somewhere in North Dakota who made that comment in passing.

Until recently, there was probably no concern about deadlines for completing a well, but it's a good question. So, if anyone knows ... a lot of readers would appreciate it.

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

Responses

12:50 p.m. CT, same day:  You asked readers for help in finding information on subject. The only definitive ND official information I have found is at: http://www.legis.nd.gov/information/acdata/pdf/43-02-03.pdf?20150408122852. See Section 43-02-03-55. Abandonment of wells or treating plants - Suspension of drilling.

The pertinent first paragraph reads:

1. The removal of production equipment or the failure to produce oil or gas, or the removal of production equipment or the failure to produce water from a source well, for one year constitutes abandonment of the well. The removal of injection equipment or the failure to use an injection well for one year constitutes abandonment of the well. The failure to plug a stratigraphic test hole within one year of reaching total depth constitutes abandonment of the well. The removal of treating plant equipment or the failure to use a treating plant for one year constitutes abandonment of the treating plant.

Generally speaking, when I review file reports, wells that have not been completed have little to no production. 

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.