Random Update On An Old Oasis Case Looking To Put Nearly Two Dozen Wells On a 640-Acre Spacing Unit -- August 7, 2019

Spoiler alert: long note, but there is nothing new here. I was simply checking up on an old case. For my benefit only; not of any use to readers. 

Most concerning: of the 12 wells in the drilling unit, it appears only six are producing and only two of them are any good. 

Re-posting part of an earlier note:

Generally speaking, fourteen wells is about the maximum number of wells I've seen in any 1280-acre drilling unit in the Bakken. If any 1280-acre unit has more than fourteen wells, they are few and very far in between.

However, in the August, 2019, NDIC hearing dockets:

Case 27809, Newfield, Siverston-Bakken; 14 wells on each of two existing 1280-acre units; 6/7-150-98; and, 30/31-151-98, McKenzie; already 6 wells on each of these units; this will make it 20 wells in each of these 1280-acre units;

Reminder: that's a case, not a permit.

It's been said that operators won't drill wells in the Bakken if the EUR is not at least one million bbls.

There is an interesting look at dollars / acre at the original post, but I wanted to re-post that note to also note this older case from a post dated January 31, 2014:

From the February, 2014, NDIC hearing docket:

• 21849, Oasis, Sanish-Bakken, 21 horizontal wells on a 640-acre unit, 4-153-93, Mountrail,

[For newbies: when the drilling started in the Bakken back in 2007, the "word on the street" was one well per section. Folks got excited when they heard talk of four wells in a 1280-acre spacing unit. Now: 21 wells in one section, one 640-acre spacing. Who wudda thought -- just in the past three or four years. I think it's incredible. And that's why the Bakken never ceases to amaze me.]

At that link are the graphics of that area. 

So, what does that section (section 4-153-93) look like today? It has not changed:

• there are still 12 horizontal wells in that section;
• it is still spaced at 640 acres; however,
• section 4 is now part of an overlapping 2560-acre unit

Moving To Twenty Wells In 1280-Acre Drilling Units In The Bakken -- August 6, 2019

Generally speaking, fourteen wells is about the maximum number of wells I've seen in any 1280-acre drilling unit in the Bakken. If any 1280-acre unit has more than fourteen wells, they are few and very far in between.

However, in the August, 2019, NDIC hearing dockets:

Case 27809, Newfield, Siverston-Bakken; 14 wells on each of two existing 1280-acre units; 6/7-150-98; and, 30/31-151-98, McKenzie; already 6 wells on each of these units; this will make it 20 wells in each of these 1280-acre units;

Reminder: that's a case, not a permit.

It's been said that operators won't drill wells in the Bakken if the EUR is not at least one million bbls.

Back of the envelope ciphering:

20 wells x one million bbls (EUR) = 20 million bbls

20 million bbls x $50 / bbl = $1,000,000,000 ($1 billion)

Each well with  infrastructure, etc: $10 million/well (wells are now costing about $6 million to drill/complete).

20 wells x $10 million/well = $200,000,000 ($200 million)

$1 billion - $200 million = $800 million

$800 million / 1280 acres = $625,000 / acre.

Peak Oil? I Don't Think So -- Staggering -- November 6, 2018

I don't know if folks remember this graphic from January, 2013.

Six wells in each formation, middle Bakken and three benches of the Three Forks = 24 wells in each 1280-acre drilling unit.

The graphic above actually shows eight wells targeting each of the four formations, or 32 wells.

A bit outrageous?

Look at this, from the November, 2018, Oasis corporate presentation:

The Permian.

Peak oil? I don't think so.

Some Data Points From CLR's Most Recent Presentation -- August, 2014; Current CLR Wells Averaging 603K-EUR; Newer Wells With Different Frack Completion Techniques Averaging Around 800K-EURSs

CLR presentations can be found at this link.

Some data points rounded; all information below pertains to the Williston Basin Bakken; the data from SCOOP is not included except in two early bullets.

Still the #1 producer in the Rockies

• Bakken: 1.2 million acres leased
• SCOOP: 460,000 acres leased

Production

• 168K boepd
• up 24% over 2013
• Bakken: 109K boepd
• SCOOP: 34K boepd

Proved reserves

• 1.2 billion boe
• up 31% yoy

Pilot Density Projects

• 1320 feet and 660 feet

1320-foot same-zone spacing density projects (16 wells in one 1280-acre unit)

• middle Bakken: 4
• TF1: 4
• TF2: 4
• TF3: 4
• Hawkinson, Tangsrud, Rollefstad

660-foot same-zone spacing density projects (32 wells in one 1280-acre unit)

• middle Bakken: 8
• TF1: 8
• TF2: 8
• TF3: 8
• Wahpeton, Lawrence, Mack, Hartman

Slide 8: Hawkinson Pilot -- all 14 wells trending on average 50% above CLR's 603,000 boe EUR model after 190 to 250 producing days

• standard frack design: 100,000 proppant per stage
• 30 total stages
• does not say if Slick Water used for these (I don't think so); SW used elsewhere with success
• validates full-field development
• demonstrates vast resource potential
• micro-seismic study

CLR makes micro-seismic history in the Hawkinson

• the Hawkinson density test is the most extensive down-hole micro-seismic study completed in the world
• most feet tractored on a single job: 59 miles
• 63-day, 24/7 operation
• 165 monitoring days
• longest laterals monitored/tractored: 21,120 feet

Large Proppant or Slick Water approaches studies

• large proppant volume: EURs trend 39% higher than CLR's average 
• large proppant volume: EURs trend 30% higher than neighboring wells
• slick water: EURs trend 35% higher than CLR's average
• slick water: EURs trend 25% higher than neighboring wells
• incremental costs of large proppant volume or slick water: $2 million

Strong liquidity -- slide #23 is interesting

• coming due, 2019, $0; credit facility of $1.75 billion
• callable, 2020: $200 million at 7.4%
• callable, 2021: $400 million at 7.1%
• callable, 2022: $2 billion at 5%
• callable, 2023: $1.5 billion at 4.5%
• callable, 2024: $1 billion at 3.8%

Realized price per bbl -- slide #24 is interesting

• 2009: $54
• 2010: $71
• 2011: $88
• 2012: 84
• 2013: $90
• 2Q14: $92
• 1H14: $$91

Total cash costs significantly less than realized price per bbl

• 2009: $14
• 2010: $16
• 2011: $18
• 2012: $17
• 2013: $19
• 2Q14: $19
• 1H14: $19

Recoverable (this slide is unchanged)

• OOI: 903 billion bbls (the slide: "903 BBo")
• at 3.5%: 32 billion bbls ("32 BBo recoverable at 3.5%)
• at 4%: 36 billion bbls
• at 5%: 45 billion bbls

Reminder: CLR's Corporate Presentation, June, 2014 Is Available

PDF at the CLR website.

In the June, 2014, NDIC dockets:

• 22545, CLR, Cedar Coulee-Bakken, 16 wells on each existing 1280-acre unit in Zones IV, Vi, and VI; 32 wells on each 2560-acre unit in Zones VII, VIII, and IX, Dunn
• 22546, CLR, Corral Creek-Bakken, 16 wells on each existing 1280-acre unit within Zones II, III, and IV, Dunn
• 22547, CLR, Jim Creek-Bakken, 16 wells each existing 1280-acre unit within Zones I, II, III, IV, V, and VI; 16 wells on each existing 1920-acre unit within Zone VII; 32 wells on each 2560-acre unit in Zones VIII and IX; Dunn
• 22548, CLR, Haystack Butte-Bakken, 16 wells on each existing 1280-acre unit within Zones II, III, IV, V, and VI; 32 wells on each 2560-acre unit in Zone VII; Dunn, McKenzie
• 22549, CLR, Rattlesnake Point-Bakken, 16 wells on each existing 1280-acre unit withink Zones I, II, and III; 16 wells on each existing 1920-acre unit within Zone IV; 32 wells on each 2560-acre unit in Zones V and VI; Dunn
• 22550, CLR, Oakdale-Bakken, 16 wells on each existing 1280-acre unit within Zone I; 32 wells on each 2560-acre unit in Zones III and IV; Dunn
• 22551, CLR, Chimney Butte-Bakken, 16 wells on each existing 1280-acre unit within Zones I, II, III, IV and V; 32 wells on each 2560-acre unit in Zones VI, VII, VIII, IX, and X; Dunn

If you are wondering how 32 wells in one drilling spacing unit (DSU) are spaced in each formation, go to slide #9 of the 34-slide presentation.

While you are at the presentation, look at slide #10. For quite some time, CLR has estimated the "average" EUR across the Bakken to be 603,000 boe. In slide #10, note the comments about the "robust Hawkinson pad:

• 13 of the 14 wells on the Hawkinson pad are trending 50% above 603,000 boe model EUR
• the Hawkinson wells were completed using "standard design," 100,000 lbs proppant/stage, and 30 stages

Comment: a long, long time ago, I opined that placing new wells near existing wells would improve EURs. A lot of folks suggest otherwise. [1.5 x 603,000 = 900,000 boe, something Filloon predicted for quite some time for the better Bakken]

Then go to the next slide, the "promising preliminary results of the Rollefstad pad:

• existing well IPs averaged 1,330 boe
• new well IPs averaged almost 3,000 boe
• 7 wells completed with 200,000 lbs of proppant, 30 stages (30 x 2 = 6 million lbs)
• 1 well was completed with 300,000 lbs, 30 stages (30 x 3 = 9 million lbs)

Nine million lbs is similar to the amount EOG is using but EOG is using significantly more stages, and thus less proppant per stage (if I remember correctly) 

The entire presentation is worth viewing. Slide #25 is a "sleeper." There are two graphics on that slide. Look at the one on the right: the "603,000 BOE EUR Model." Note the x-axis. Three generations of roughnecks, roustabouts, and maintainers will be drilling and maintaining CLR wells.

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Another Inconvenient Truth

The chart-of-the-day, Carpe Diem. 

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 Whistling Past The Graveyard

I still get a kick out of mainstream media spin. After another horrendous job report today, Reuters is still able to post this headline: "Economy On Solid Ground Despite Cooler Hiring." For months, maybe years, Reuters has been telling us that the data suggests employers are laying off fewer folks, hiring more. 

CLR's Well-Spacing Pilot Projects -- Previously Posted

CLR's May, 2013, corporate presentation (this is a dynamic link, and the presentation will change over time), a PDF:

Slide 31: CLR's 160-acre density spacing for the middle Bakken and Three Forks formations. I've seen this slide before and I think I've even posted links to it with comments. Some observations:

the 320-acre spacing pilot project

• long laterals on 1280-acre spacing units
• 4 wells per formation (that's where the 320-acre spacing comes from: 1280 acre/4 = 320 acres)
• 4 formations (MB, TF1, TF2, TF3)
• 23 net wells across three pilot projects
• $123 million net cost/23 net wells = $5.3 million/well

the 160-acre spacing pilot project

• long laterals on 1280-acre spacing units
• 8 wells per formation (that's where the 160-acre spacing comes from: 1280 acre/8 = 160 acres)
• 4 formations (MB, TF1, TF2, TF3)
• 6 net wells - one pilot project
• $36 million net cost/6 net wells = $6 million/well

The Wahpeton Family Of Wells: Another Look At CLR's Testing The Lower Benches of the Three Forks, Banks Oil Field; Natural Gas Flaring Continues to Decrease (As A Percentage of Production) -- January 27, 2013

Updates

July 22, 2020: 

• 335914, SI/A, CLR, Wahpeton 16-16H1, 33-053-08890, Banks, t--; cum 116K over 3 months,7 days; fracked 12/6/2019 - 12/17/2019; 7.143 million gallons of water; water 88.52% by mass; Three Forks first bench; vertical operations required three BHAs; curve build with one BHA, no problems; the lateral was completed with a single BHA; drilled out of the shoe on July 29, 2019; TD reached on August 2, 2019; four days to drill the lateral; background gas, moderate;

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
BAKKEN	5-2020	31	29504	29655	24396	53683	53276	0
BAKKEN	4-2020	30	25690	25268	24697	41414	41020	0
BAKKEN	3-2020	31	42567	43003	40235	66283	66283	0
BAKKEN	2-2020	7	17874	17185	14630	23089	22139	950
BAKKEN	1-2020	3	117	117	2218	758	0	758

 

July 19, 2020: another CLR Wahpeton well comes off the confidential list this week.

• 35914, conf, CLR, Wahpeton 16-16H1, Banks,

Date	Oil Runs	MCF Sold
5-2020	29655	53276
4-2020	25268	41020
3-2020	43003	66283
2-2020	17185	22139
1-2020	117	0

July 12, 2020: updated graphic --

June 4, 2020: see this post. Updated graphics:

June 3, 2020: production data update, see below: see this update --

• 35915, SI/A, CLR, Wahpeton 17-16H, Banks, t--; cum 107K in 2.5 months;

November 28, 2017: production data updated; five wells now AB/TA. 

December 11, 2016: production of these wells updated; see below; five wells now IA/AB/TA. 

February 9, 2014: screenshot of the Wahpeton Pad, this date.

September 11, 2013: from Mike Filloon --

The most important is the Wahpeton Pad. Continental chose the important location to drill a total of 32 wells from the middle Bakken to the 3rd bench. Since this was the first 160-acre pilot project, it very well could be the best area overall for pad drilling. 

Original Post

From a Continental Resources exhibit. Sent in by a reader:

The Wahpeton wells are sited in section 16, and run north to south, ending in section 21. This page is updated periodically, last update, July 12, 2020.

• 19450, 322, CLR, Wahpeton 1-16H, Banks, t7/11; cum 253K 4/20; off line 5/20;

• 24843, 1,050, CLR, Wahpeton 6-16H, Banks, t6/14; cum 176K 4/20; off line 5/20;
• 24809, 1,786, CLR, Wahpeton 9-16H, Banks, t5/14; cum 221K 4/20; off line 5/20;
• 24840, 382, CLR, Wahpeton 4-16H1, Banks, t7/14; cum 85K 4/20; off line 5/20;
• 24810, 550, CLR, Wahpeton 8-16H1, Banks, t6/15; cum 138K 4/20; off line 4/20;
• 24807, 354, CLR, Wahpeton 11-16H1, Banks, t6/14; cum 101K 4/20; off line 4/20;
• 24837, 652, CLR, Wahpeton 2-16H2, Banks, t6/14; cum 122K 4/20;
• 24842, IA/411, CLR, Wahpeton 5-16H2, Banks, t6/14; cum 69K 2/20; off line 2/20; remains off line 5/20;
• 24808, IA/IAW/AB/IA/366, CLR, Wahpeton 10-16H2, Banks, t6/14; cum 20K 6/19;
• 24804, AB/IAW/AB/1,031, CLR, Wahpeton 14-16H2, Banks, t5/14; cum 24K 8/15;
• 24838, TA, CLR, Wahpeton 3-16H3, Banks, no production;
• 24844, IAW/AB/334, CLR, Wahpeton 7-16H3, Banks, t6/14; cum 23K 5/16;
• 24806, A/IAW/AB/1,031 CLR, Wahpeton 12-16H3, Banks, t5/14; cum 17K 3/20; off line 4/20;
• 24805, 1,612, CLR, Wahpeton 13-16H3, Banks, t5/14; cum 213K 5/20; remains on line in 5/20;

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Meanwhile, the "Charlotte" wells sited in either section 22 or 27-152-99, Banks, but all probably drilling 22/15-152-99:

• 19918, 496, Charlotte 1-22H, middle Bakken, SWSE 22-152-99; Banks, 30 stages; 2.5 million lbs; t6/11; cum 360K 4/20; total depth: 21,090 feet;
• 23664, 657, Charlotte 3-22H, Banks, TF1, SESE 22-152N-99W, t11/12; cum 186K 4/20;
• 21128, 692, Charlotte 2-22H, Banks, TF2, SWSW 22-152-99; 30 stages; 2.3 million lbs; t10/11; cum 255K 4/20; total depth: 21,358 feet;
• 23612, 673, Charlotte 4-22H, TF3, 4 secs, Banks, [Update: see press release, December 3, 2012], t7/13; cum 173K 4/20;
• 23608, 1,303, Charlotte 5-22H, Banks, ?TF4, 4 secs; t6/13; cum 248K 4/20;
• 23664, 657, CLR, Charlotte 3-22H, Banks, t11/12; cum 186K 4/20;

So, unless I'm misreading the GIS map server and/or the permits, it appears the Wahpeton wells will be parallel to the Charlotte wells, in adjoining sections (spacing units). But the Wahpeton wells will be running north-to-south; and the Charlotte wells will be running south-to-north.

By the way, look at #23664, Charlotte 3-22H, still confidential, but production runs for first month:

Date	Oil Runs	MCF Sold
11-2012	7583	12383

What do you notice?  Yes, it was hooked up to a natural gas pipeline almost immediately. As the well density increases, the natural gas flaring will take care of itself. Already we are starting to see this happen on a larger scale. In the most recent Director's Cut:

Additions to gathering and processing capacity are helping with the percentage of gas flared dropping to 29%. The historical high was 36% in September 2011.

With more wells/month being drilled; more production/well; to see a downward trend this early in the boom speaks volumes about a non-issue.

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And, then, of course, to the east, in the next spacing unit to the east are the very good Chicago/Syracuse wells.