Sunday, June 23, 2019

Extreme Limited Entry Perforating -- Fracking In The Bakken -- June 23, 2019

Disclaimer: I am inappropriately exuberant about the Bakken.

Disclaimer: I have no formal (or, for that matter, informal) training or experience in the oil sector, so I'm probably getting ahead of my headlights with regard to some of the comments I will be making later.

First, this. Earlier this morning I mentioned that there seemed to be a "quantum" jump in the quality of the Bakken wells (based on 24-hour, 30-day, 60-day, and 90-day IPs) when going through the 2017 Bakken permits. It appeared that somewhere between 2016 and 2017, things in the Bakken changed significantly with regard to better wells.

One almost wonders if the "near-death" experience visited upon the Bakken operators by Saudi Arabia (2014 - 2016) forced "them" to improve their strategies and technologies.

I remember early on, during this time, maybe even as late as 2016, really, really smart oilmen simply said, "more sand, more oil." It was all about simply adding more and more sand.

But look at the completion strategies in 2018 and going forward: maybe they're using more and more sand in the Permian, but in the Bakken, it appears we're leveling out at around 8 million lbs and fewer, rather  than more, stages. Granted, "we're" drilling in the "best" spots in the Bakken but that would be true in the Permian, too, I assume, and yet some of the best Bakken wells I've seen used less than 8 million lbs sand and only 35 stages.

Much could be written, but let me post what a reader sent me. It's obvious he's been thinking about this even more than I (have been thinking about it). Here was the reader's note [the comments in red/bold are mine, not the reader's]:
Somewhat brief, hopefully accurate, theory concerning the increase in IPs in the 2016 - 2017 timeframe ...

Many operators had, by that time, started to declare that diverters were being used in completions.

EOG most probably started this earlier as they depicted controlled, HIGHLY increased fracture intensity in their presentations prior to 2016.

Fast forward to today and the ramifications of Extreme Limited Entry (XLE) ...

I have studied the September, 2018, article from from Liberty Resources regarding Extreme Limited Entry in attempts to fully "get" what is happening and project future implications. [To repeat: the September, 2018, article from from Liberty Resources regarding Extreme Limited Entry.]

Exciting stuff.

In a ultra condensed nutshell, what these operators are doing is maintaining a VERY high pressure "bubble" underground so as to induce fractures (technically, opening up pre-existing fractures. This is a crucial - yet often overlooked distinction).

This pressure "bubble" functions best if it can be maintained at 1,500-2,000+ psi to induce connectivity (create complex fractures).

By identifying homogeneous rock that will tend to fracture with similar pressure levels, thief fractures will be minimized. (This directly ties in with the number, length, and placement of stages as each stage is a somewhat 'stand alone' entity. [This is so incredibly cool.]

Using extremely sturdy metal, the perf entry points - precisely located - will not enlarge as a consequence of proppant friction. A ton of sand per linear foot is a LOT of scouring material.

Perf clusters now number 13 to 15 per stage, up from 3 in earlier years.

Diverters, both near wellbore and far field, are used to temporarily block undesirable frac propagation so as to bring about an optimal case of Stimulated Reservoir Volume (SRV).

Speculative bonus regarding halo effect?

I am starting to suspect that later frac jobs are deliberately "touching" earlier wells' drainage area by fracturing and propping unstimulated areas of the parent wells' rock and enabling the newly frac'd/propped reservoir to flow into the older wells' wellbores.
Isn't that interesting?

Now this, for free. I am providing a link at no extra cost -- free to all subscribers -- JPT Extreme Limited Entry Perforating. I had completely missed this paper. Again, thanks to a reader I've learned more about the Bakken. I find this absolutely fascinating.

Yes, I know. I am inappropriately exuberant about the Bakken.

By the way, the article the reader was referencing: an "editor's choice" article from September, 2018.

I've been focused on the halo effect, what is now called the "parent well uplift" phenomenon. It's very possible the oil industry was more concerned with damaging parent wells when drilling new wells, which ultimately led to extreme limited entry perforating. I agree with the reader: my hunch is that the operators are choosing very, very carefully where best to put daughter wells and how to best complete (frack) them.

The operators are probably more concerned about preventing damage to existing wells. I'm fascinated by the parent-well uplift phenomenon. It appears these may simply be two sides of the same coin.

Again, as mentioned earlier, I'm probably getting well ahead of my headlights.

Notes From All Over -- Part 2 -- June 23, 2019

China and tariffs: I think China got the memo: they are about to lose some big customers if they don't get back to the negotiating table with the US regarding tariffs.

Apple Inc has said it has started exploring moving some production out of China. This is not a trivial decision. If Apple moves some production out of China, others will follow. 

Apple may or may not be serious; part of this may be a strategy to get China back to the bargaining table.

Notes From All Over -- Part 1 -- June 23, 2019

Bureaucracy run amok: LaCroix is technically illegal in Massachusetts. To sell canned water in the commonwealth one needs a permit. LaCroix does not have a permit. Minor detail. Link here.
If LaCroix makes it official with The Bay State, it's not clear if the water's mysterious all-natural essences will finally be revealed. But at least the public can be fully reassured that their beloved pamplemousse is free of any radioactive materials.
So, now we have:
  • pamplemousse
  • penultimate
  • picayune
  • puisne
Some in France might refer to President Trump as a pamplemousse. LOL.

Upfront Costs

Connecticut is considering highway tolls to pay for highway maintenance.

Connecticut is the only state along the East Coast that doesn’t collect tolls on highways. The majority of states have some form of tolling.

There are at least two issues here:
  • the political issue -- whether to reinstate tolls; and,
  • building the system
Here in Texas no manned tollbooths. No slowing, stopping, paying, accelerating. It's all done with RFID and cameras, which has become the norm across the US.

That is how Connecticut will do it -- electronically. Even Massachusetts finally switched over in late 2016.

And that's the rub: it won't be cheap. There will be substantial upfront costs.

Sports Sunday -- June 23, 2019

Indy racing: Grand Prix at Road America.
  • the course
  • Alexander Rossi wins by an incredible 30 seconds or thereabouts
Women's Soccer: see updates here.

PGA golf: not particularly interested in watching today.

NASCAR: Sonoma Raceway, a 2.5-mile road course.

The Geography Page

Sophia pointing out where Corky's grandparents live: Wyoming.

A Snapshot In Time -- North Dakota Oil And Gas Permits Issued In 2017


Later, 6:49 p.m. Central Time: after posting the original post, a reader sent in a most interesting comment. Posted here.

Original Post

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

Disclaimer: I often make errors in simple arithmetic.

Disclaimer: my numbers won't agree with those of the NDIC but they will be close enough for my purposes.

Disclaimer: the numbers "may not add up." They will be close but errors are likely.

Disclaimer: this was done quickly and was not proofed.

Disclaimer: I did most of this while watching Alfred Hitchcock's To Catch A Thief. I was often distracted by the dialogue.
  • The best line, Cary Grant: It seems I can't get out of this gracefully
  • The most memorable line that got past the censor, Grace Kelly: Would you like a leg or a breast? [She brought chicken for their picnic.]
  • More later.
Disclaimer: this list is apt to change by tomorrow. Any well on DRL status could be completed tomorrow; some permits could expire; etc., etc.

Disclaimer: Not all disclaimers have been listed.

Note: IPs are taken from the scout tickets; generally 24-hour flow rates, as far as I know. We've discussed the relevancy/irrelevancy of such IPs in the past. IPs cannot be compared between operators. If 24-hour IPs are meaningful at all, they are only meaningful when compared for one operator. In other words, one cannot compare the historically low IPs reported by BR with the historically high IPs reported by MRO.

Note: factors affecting IPs -- to list just a few --
  • completion strategies
  • natural fractures
  • skill / experience of the frack spread
  • percent of wellbore within the target
  • formation target (middle Bakken; Three Forks, varying benches)
  • the oil field (and that affected by porosity, pressure, permeability, TOC, etc)
Note: IPs on the scout tickets reported by BR "never" correlate with how good the BR wells turn out. The IPs on the scout tickets reported by MRO almost always correlate with how good those MRO wells will be.

I don't have the resources, nor the intelligence, nor the interest, to do a statistical analysis regarding any of this data. But going through each scout ticket since 2007, and I have seen every scout ticket since 2007 at least once, it seems there was a jump in 24-hour IPs, 30-day IPs, 60-day IPs, and 90-day IPs somewhere between 2016 and 2017.
And the jump in these initial production numbers were not subtle. The Bakken operators made a huge jump in initial production numbers somewhere between 2016 and 2017. I will provide some examples later. But it is quite amazing. See this post.
  • Relevant history:
    • 2014 - 2016: Saudi Arabia tried to "break" US shale operators
    • 2016: record low number of permits issued during Bakken boom
    • 2017: resurgence in shale permits
  • 2020, October 31: 645 permits; at this pace: day 305 in a leap year (366 days): 774 permits
  • 2019, projected for the year (as of June 21, 2019) --- 1,523; in fact, actual: 1,397
  • 2018: 1,466
  • 2017: 1,189
  • 2016: 818
  • 2015: 2,055
  • 2014: 3,012
  • 2013: 2,671
  • 2012: 2,522
  • 2011:1,916
The Data

If I recall correctly:
  • wells must be spud within a year of permits being issued, but $100 will renew lapsing/expiring permits
  • once spud, wells must be completed within two years; waivers by exception
Permits issued in calendar year 2017:
  • First permit: 33243
  • Last permit: 34431
  • Total permits: 1,189
Status of permits / wells (data reviewed June 21 - 23, 2019; NDIC data dated 4/19):
  • TA: 2
  • SI (DUCs): 87
  • PNC: 56
  • loc: 111
  • dry: 12
  • drl: 26
  • conf: 166
  • with IPs: 729
Permits by operator:
  • Abraxas: 11
  • Armstrong Operating: 2
  • Ballard: 1
  • BR: 60
  • Bruin: 1
  • CLR: 82
  • Crescent Point Energy: 83
  • Enerplus: 44
  • EOG: 55
  • Foundation Energy: 1
  • Freedom Energy: 1
  • Hess: 94
  • HRC: 3
  • Iron Oil Operating: 1
  • Kraken Operating: 37
  • Liberty Resources: 14
  • Lime Rock Resources: 15
  • Missouri River Resources: 9
  • MRO: 95
  • Newfield: 17
  • Nine Point Energy: 3
  • NP Resources: 29
  • Oasis: 126
  • Petro Harvester: 19
  • Petro-Hunt: 15
  • Petroshale: 2
  • QEP: 27
  • Resonance Exploration: 4
  • Resource Energy Can-Am: 4
  • RimRock: 2
  • SHD Oil & Gas: 7
  • Sinclair: 5
  • Slawson: 23
  • Statoil: 44
  • Triangle USA: 2
  • UND EERC: 2
  • White Butte: 18
  • Whiting: 115
  • Windridge: 5
  • WPX: 44
  • XTO: 65
  • Zavanna: 2
Non-Bakken permits: 14
  • Madison:10
  • Amsden: 2
  • Red River: 1
  • Lodgepole: 1
SI/NC by operator:
  • CLR: 9
  • Crescent Point Energy: 7
  • Enerplus: 2
  • Hess: 1
  • HRC: 2
  • MRO: 5
  • Oasis: 2
  • Petro-Hunt: 2
  • Statoil (Equinor): 23 (deep pockets)
  • Whiting: 3
  • WPX: 2
  • XTO: 28 (deep pockets)
MRO wells / permits: 
  • SI: 5
  • PNC: 2
  • conf: 4
  • IPs: 84 wells with reported IPs (bopd)
    • average IP: 4,640 bopd
    • range: 1,306 - 8,475 bopd
      • 8,000 and above: 2
      • 7,000 - 7,999: 4
      • 6,000 - 6,999: 10
      • 5,000 - 5,999: 16
      • 4,000 - 4,999: 23
      • 3,000 - 3,999: 20
      • 2,000 - 2,999: 6
      • 1,000 - 1,999: 3

CLR Colter Wells In Bear Creek

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

The CLR Colter wells in Bear Creek are beginning to report. Scroll through the list at this post as well as the data below on this post to see some incredible Colter wells. It appears:
  • three targets: middle Bakken; Three Forks, first bench; Three Forks, second bench
  • in addition, one well may have targeted the third bench (based on legal name of the well); geologic record not on file; NDIC has asked for geologic record for that well (see below)
  • medium amount of sand: 7.05 million to 7.06 million lbs
  • small number of stages: 37
The wells:
  • 16988, 375, CLR, Colter 44-14H, Bear Creek, t10/08; cum 508K 8/19; small jump in production, 3/19; several big Colter wells came on line that month;
  • 19616, 728, CLR, Colter 2-14H, Bear Creek, t7/11; cum 410K 8/19; off line 8/18 to 3/19; only 12 days in 4/19;
  • 24060, 256, CLR, Colter 3-14H-2, Bear Creek, t6/13; cum 124K 8/19; offline from 8/18 to 4/19;
  • 24431, 1,113, CLR, Colter 5-14H3, Three Forks NOS; Bear Creek, t6/13; cum 303K 8/19; off line as of 3/19; still offline 4/19; offline from 8/18 to 2/19; TD = 22,770 feet; 30 stages; 1.7 million lbs; sand/ceramic; no geologic report on file; NDIC has asked for a geologic report to be filed;
  • 26721, 1,268, CLR, Colter 6-14H2, Bear Creek, t3/14; cum 454K 8/19; off line from 8/18 to 2/19; no bump in production noted;
  • 32892, 1,600, CLR, Colter 9-14H, Bear Creek, t5/19; cum 97K 8/19;
  • 32893, 1,151, CLR, Colter 10-14H, 48 stages, 10.2 million lbs, Bear Creek, a 50K+/month well; t3/19; cum 215K 8/19; 55K in March, 2019
  • 32894, 1,563, CLR, Colter 11-14H2, Bear Creek, t3/19; cum 132K 8/19; 41K in March, 2019
  • 32895, 1,311, CLR, Colter 12-14H, Bear Creek: t3/19; cum 125K 8/19;
  • 32896, 952, CLR, Colter 13-14H1, Bear Creek, t3/19; cum 209K 8/19; 46K in March, 2019;
  • 32897, 863, CLR, Colter 14-14H, Bear Creek, t3/19; cum 87K 8/19; off line 6/19; remains off line 8/19;
  • 34094, 2,479, CLR, Colter 7-14H, 37 stages, 10.2 million lbs, Bear Creek, t3/19; cum 197K 8/19;
  • 34095, 2,457, CLR, Colter 8-14H1, 41 stages; 10.2 million lbs; Bear Creek, t3/19; cum 174K 8/19;
Of note:
  • 27740, XTO, Brandvik, taken off line 8/18; brought back on line 4/19; 15 days in 4/19;
The graphics:

Northwest corner of Dunn County:

Some early production numbers:
  • 32896, H1, 48 stages; 7.1 million lbs:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
  • 32893, middle Bakken:
    PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
  • 32894, H2, 37 stages; 7.1 million lbs;
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare
  • 32895, middle Bakken:

DateOil RunsMCF Sold

  • 32897, middle Bakken, 37 stages, 7.1 million lbs:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

From the file reports.
  • 32896:
    • spud date: February 6, 2018
    • TD date: March 3, 2018
    • TD: 21,684 feet
    • target: Three Forks, first bench
    • drilled out of the shoe: February 27, 2018
    • two trips were necessary; both near the end of the lateral
    • background gas: very low
    • Mississippian Lodgepole: 10,260 feet
    • Mississippian Upper Bakken: 11,122 feet
    • Lower Mississippian-Upper Devonian Middle Bakken: 11,139 feet
    • middle Bakken: 34 feet thick
    • Upper Devonian Lower Bakken: 11,173 feet  
    • Upper Devonian Three Forks: 11,190 feet
    • target: approx 18' thick, beginning 15' below the Three Forks top, and extending 33' below the same reference point
    • "... drilling parameters did not show any indication or warning of a shale strike (or we may have proceeded to a point of gamma confirmation), nor did the last sample, cleaned with Herculean efforts, produce any shale cuttings save those mudstone pieces typical of the Three Forks."
    • "The hypothetical conclusion drawn is that we hit something hard, and that this is likely a locally enhanced signature of the designated marker 1, and that said hard streak (sic) is what deflected us. This occurred 34' from the desired TD; as a result of this event, TD was called early."
  • 32894:
    • spud date: January 25, 2018
    • TD date: March 14, 2018
    • TD: 21,684 feet
    • target: Three Forks, second bench
    • vertical operations: two trips for MWD and two trips for motor & bit 
    • curve kicked off: January 29, 2019
    • final landing: 11,253' just inside the target top
    • Bakken shale collapse issues have been encountered in this region, and angles of intercept and shale exposure footage have become important data
    • description of drilling angle parameters provided
    • no shale collapse issues were encountered
    • drilled out of the shoe: March 11, 2018
    • only one trip was necessary; MWD tool failure
    • background gas: high -- trip gas hit 3,452 units; increase in gas as drilling continued suggested possibility of intercepting a natural fracture or possibly drilling into a localized stratigraphic trap
    • gas: common peaks exceeding 3,000 units; after the buster was deactivated, background gas averaged around 1,500 to 2,000 units
    • oil cuts were poor to fair, with the latter indicative of greater oil in the 2nd bench than previously experienced by these geologists
    • Mississippian Lodgepole: 10,255 feet
    • Mississippian Upper Bakken: 11,122 feet
    • Lower Mississippian-Upper Devonian Middle Bakken: 11,139 feet
    • middle Bakken: 33 feet thick
    • Upper Devonian Lower Bakken: 11,172 feet  
    • Upper Devonian Three Forks: 11,190 feet
    • the internal 1 shale top of the Three Forsk: 11,233 feet
    • Three Forks second bench: 11,244 feet
    • target: approx 13.5' thick, beginning 7.5' below the internal 1 shale base, and extending 21' below the same reference point
    • landing target angle was projected to be 14' below the internal 1 shale base, near the center of target  
  • 34094:
PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

From the file report for #34094:
  • spud date: June 28, 2018
  • TD date: July 18, 2018
  • target: middle Bakken
  • to the KOP, with a planned trip in the Kibbey
  • curve build began, July 1, meaning the vertical took three days
  • drilled out of the shoe on July 15th; thus, three days to drill the lateral
  • low gas (generally 400 - 600 units)
  • slight flares, 1' to 3'
  • target would be approx 13' thick, beginning 13' below the middle Bakken top, and extending ot 26' below the same reference point
  • "almost entirely" within the target

Early Production Data For Wells Coming Off Confidential List This Next Week -- June 23, 2019

Full list of wells coming off the confidential list this week is posted here. These are only the wells from that list which have recorded production. 

32895, conf, CLR, Colter 12-14H, Bear Creek:

DateOil RunsMCF Sold

34955, conf, Petro Harvester Operating Company, PTL2 04-28 164-92 A, Portal:

DateOil RunsMCF Sold

34090, conf, Oasis, Aagvik 5298 13-26 12T,  Bank:

DateOil RunsMCF Sold

34093, conf, Oasis, Nelson 5298 13-26 10B, Banks:

DateOil RunsMCF Sold
32893, conf, CLR, Colter 10-14H, Bear Creek, a 50K+/month well:

DateOil RunsMCF Sold

34092, conf, Oasis, Nelson 5298 13-26 9T,  Banks:

DateOil RunsMCF Sold

32359, conf, CLR, Antelope Federal 6-23H1, Elm Tree:

DateOil RunsMCF Sold

34092, conf, Oasis, Nelson 5298 13-26 9T, Banks:

DateOil RunsMCF Sold

32359, conf, CLR, Antelope Federal 6-23H1, Elm Tree:

DateOil RunsMCF Sold

Wells Coming Off The Confidential List This Next Week-- June 23, 2019

Six months ago it was the end of December -- Christmas week, New Year's Eve, and New Year's Day.

Monday, July 1, 2019:

Sunday, June 30, 2019: 82 for the month; 271 for the quarter;
34401, conf, WPX, Lion 18-19HC,  Mandaree, no production data, 
32895, conf, CLR, Colter 12-14H, Bear Creek, a very nice well;

Saturday, June 29, 2019: 80 for the month; 269 for the quarter;
35840, conf, XTO, Halverson 13X-33EXH, Alkali Creek, no production data,

Friday, June 28, 2019: 79 for the month; 268 for the quarter;
34955, conf, Petro Harvester Operating Company, PTL2 04-28 164-92 A, Portal, producing, 
34400, conf, WPX, Lion 18-19HY, Mandaree, no production data,

Thursday, June 27, 2019: 77 for the month; 266 for the quarter;
34090, conf, Oasis, Aagvik 5298 13-26 12T,  Banks, a nice well;

Wednesday, June 26, 2019: 76 for the month; 265 for the quarter;

Tuesday, June 25, 2019: 76 for the month; 265 for the quarter;
34093, conf, Oasis, Nelson 5298 13-26 10B, Banks, a nice well; 
32893, conf, CLR, Colter 10-14H, Bear Creek, a 50K+/month well;

Monday, June 24, 2019: 74 for the month; 263 for the quarter;
34398, conf, WPX, Lion 18-19HX, Mandaree, no production data,

Sunday, June 23, 2019: 73 for the month; 262 for the quarter;
34092, conf, Oasis, Nelson 5298 13-26 9T,  Banks, a nice well;

Saturday, June 22, 2019: 72 for the month; 261 for the quarter;
34397, conf, WPX, Lion 18-19HA, Mandaree, no production data,
32359, conf, CLR, Antelope Federal 6-23H1, Elm Tree, a huge well;