Closer Look At A Second Bench Three Forks Well -- CLR Hereford Federal -- February 10, 2020

The well;

• 32354, 174, CLR, Hereford Federal 8-20H2, 55 stages; 13.43 million lbs; Elm Tree; early production suggests a poor well; stimulated 3/28/2017; t8/14/2019; cum 11K 12/19;

From the file report:

• spud: March 20, 2016
• TD date: April 6, 2016
• target: upper Devonian 2nd beach Three Forks formation
• a three-section lateral;
• fourth well in these sections;
• vertical: 
• begun: March 20, 2016
• reached KOP: March 26, 2016
• upon reaching this depth, it was noted that target was deeper than prognosis
• drilled out of the show: March 28, 2016
• reached TD: April 6, 2016
• TD: 27,242 feet
• low gas units; rare flares, 1' to 5' in height, brief in duration;
• horizontal: 98% in the delineated target zone;
• "This well was somewhat unique, in that we had fair control from the parallel Buelingo 1-20H well to the east of us for the first section, but thereafter we had little data to confirm the structure interpretation ahead of us....[our data] will provide a better template for the other eight wells [on this] pad. It was very important, with the length of the well, to maintain a smooth well bore, in order to not interfere with sliding as we proceeded into the third section. This was also achieved, and the well reached TD without any significant down-hole interference."

See these posts:

• Hereford Federal wells tracked here;
• sister well with huge frack;

Graphics:

Increased Density In The Bakken -- The CLR Simmental Federal / Angus Federal Wells -- November 6, 2019

Locator: 10010CLRANGUS.

Updates

December 26, 2021: update here. 

June 5, 2021: CLR is starting to report these DUCs drilled back in late 2019. Oil prices were very, very low all of 2020. What a great time to starting fracking / completing these wells.

Original Post

Nomenclature:

• H: middle Bakken, 1280-acre spacing, generally
• H1: Three Forks, first bench, 1280-acre spacing, generally
• H2: Three Forks, second bench, 1280-acre spacing, generally
• HSL: middle Bakken; section line well; 2560-acre spacing generally
• HSL1: Three Forks, first bench; section line well; 2560-acre spacing generally
• HSL2: Three Forks, second bench; section line well; 2560-acre spacing generally

April 7, 2021: it appears the wells have been completed, or are in the process of being completed; runs are being reported for the first time as of 2/21;

September 15, 2020: CLR has permits for thirteen more Charolais South Federal wells in the immediate are, to the northeast, sited in section 10. See this link.

June 14, 2020: CLR to report four new Angus Federal wells this week.

• 37055, ros (1/8/20)-->drl/NC-->1,471, CLR, Angus Federal 12-9H, Elm Tree, producing, 6 days, 2/21; cum 81K 10/21; cum 282K 11/22; cum 342K 9/23; cum 414K 6/26;
• 37056, conf-->drl/NC-->drl/A, CLR, Angus Federal 11-9H2, Elm Tree, producing, 3 days, 2/21; 28K first full month, 6/21; cum 116K 10/21; cum 291K 11/22; cum 329K 9/23; cum 383K 6/26; 
• 37057, conf-->drl/NC-->drl/A, CLR, Angus Federal 10-9N, Elm Tree, producing, 4 days, 2/21; 41K first full month, 5/21; another 40K 6/21; cum 205K 10/21; cum 357K 11/22; cum 396K 9/23; cum 448K 6/26;
• 37058, conf-->drl/NC-->drl/A, CLR, Angus Federal 9-9H, Elm Tree, producing, 4 days, 2/21; 25K over 25 days, 4/21; cum 153K 10/21; cum 291K 11/22; cum 337K 9/23; cum 409K 6/26;

An 18-well pad in Elm Tree. The wells:

• 37060, conf-->drl/NC-->drl/A-->AB (5/25) , CLR, Angus Federal 7-9H, Elm Tree, producing, 4 days, 2/21; 20K first full month, 5/21; cum 75K 9/21; offline 10/21; cum 129K 11/22; cum 148K 5/24; AB;
• 37059, conf-->drl/NC-->drl/A, CLR, Angus Federal 8-9H1, Elm Tree, producing, 4 days, 2/21; 19K 6/21; cum 114K 10/21; cum 222K 11/22; cum 279K 5/24; cum 317K 6/26;
• 37058, conf-->drl/NC-->drl/A, CLR, Angus Federal 9-9H, Elm Tree, producing, 4 days, 2/21; 28K 6/21; cum 153K 10/21; cum 291K 11/22; cum 409K 6/26;
• 37057, conf-->drl/NC-->drl/A, CLR, Angus Federal 10-9H, Elm Tree, producing, 4 days, 2/21; 41K 5/21; cum 205K 10/21; cum 357K 11/22; cum 416K 5/24; cum 448K 6/26;
• 37056, conf-->drl/NC-->drl/A, CLR, Angus Federal 11-9H2, Elm Tree, producing, 3 days, 2/21; 28K 6/21; cum 116K 10/21; cum 291K 11/22; cum 383K 6/26;
• 37055, ros (1/8/20)-->drl/NC-->drl/A, CLR, Angus Federal 12-9H, Elm Tree, producing, 6 days, 2/21; cum 81K 10/21; cum 282K 11/22; cum 414K 6/26;
• 37054, conf-->drl/A, CLR, Angus Federal 13-9H2, Elm Tree, producing, 4 days, 2/21; cum 26K 10/21; cum 269K 11/22; cum 490K 6/26;
• 37053, conf-->drl/NC-->drl/A, , CLR, Angus Federal 14-9HSL1, Elm Tree, producing, 4 days, 2/21; cum 76K 10/21; cum 317K 11/22; cum 442K 5/24; cum 510K 6/26;
• 37052, conf-->drl/NC-->drl/A, CLR, Simmental Federal 5-16H2, Elm Tree, producing, 3 days, 2/21; 17K 6/21; cum 61K 7/21; off line 8/21; cum 198K 11/22;  cum 317K 6/26;
• 37051, conf-->drl/NC-->drl/A, CLR, Simmental Federal 6-16H, Elm Tree, producing, 4 days, 2/21; 27K 5/21; cum 298K 11/22; cum 379K 6/26;
• 37050, conf-->drl/NC-->drl/A, CLR, Simmental Federal 7-16H2, Elm Tree, producing, 3 days, 2/21; 24K 5/21; cum 236K 11/22; cum 275K 5/24; cum 301K 6/26;
• 37049, conf-->drl/NC-->drl/A, CLR, Simmental Federal 8-16H, Elm Tree, producing, 4 days, 2/21; 24K 6/21; cum 260K 11/22; cum 318K 6/26;
• 37048, conf-->drl/NC-->drl/A, CLR, Simmental Federal 9-16H1, Elm Tree, producing, 4 days, 2/21; 17K 6/21; cum 169K 11/22; cum 221K 6/26;
• 37047, drl/drl-->drl/NC--drl/A, CLR, Simmental Federal 10-16H, Elm Tree, first production, 4/21, t--; cum 96K 6/21; cum 264K 11/22; cum 305K 6/26;
• 37046, conf-->drl/NC--drl/A, CLR, Simmental Federal 11-16H2, Elm Tree, first production, 5/21, t--; cum 48K 6/21; total drilling days, 11; second bench, Three Forks; target: land the wellbore 66' below the Three Forks formation top, but more specifically 12' into the Three Forks 2nd bench; the wellbore stayed within the ideal 12' target window 93.4% of the production lateral length; cum 232K 11/22; cum 297K 6/26;
• 37045, conf-->drl/NC--drl/A, CLR, Simmental Federal 12-16H, Elm Tree, producing, 6 days, 2/21; cum 183K 11/22; cum 280K 6/26;
• 37044, conf-->drl/NC--drl/A, CLR, Charolais South Federal 2-10HSL, Elm Tree, producing, 5 days, 2/21; cum 376K 11/22; cum 471K 5/24; cum 512K 6/26;
• 37043, ros (1/8/20)-->drl/NC--drl/A, CLR, Simmental Federal 13-16HSL2, Elm Tree, producing, 4 days, 2/21; cum 156K 11/22; cum 310K 6/26;

• 23493, 568, CLR, Simmental Federal 4-16H, Elm Tree, t6/13; cum 342K 12/20; was offline 4/20 - 5/20; off line again, 1/21; remains off line 2/21; back on line 3/21; off line 5/21; cum 355K 6/21; cum 357K 10/21; cum 374K 11/22; cum 389K 5/24; cum 398K 6/26;
• 23494, 360, CLR, Angus Federal 5-9H, Elm Tree, t6/13; cum 489K 11/20; off line 11/19; back on line 1/20; off line 4/20 - 5/20; off line, again, 12/20; remains off line, 3/21; back on line 4/21; cum 504K 6/21; cum 535K 11/22; cum 552K 5/24; cum 559K 6/26;
• 23495, 240, CLR, Simmental Federal 3-16H, Elm Tree, t6/13; cum 372K 12/20; off line for short periods of time in 11/19 and 12/19; off line 4/20 - 5/20; appears to have come off line12/20; back on line 2/21; one day of production, 2/21; six days, 3/21; back off line 5/21; cum 378K 5/21; cum 384K 11/22; cum 400K 6/26;
• 23496, 300, CLR, Angus Federal 4-9H, Elm Tree, t5/13; cum 390K 12/20; off line 4/20 - 5/20; off line 11/20?; off line 12/20; remains off line 2/21; six days, 3/21; cum 424K 6/21; cum 471K 11/22; cum 479K 5/24; cum 485K 6/26;

To date (9/19):

• middle Bakken: 13
• Three Forks, first bench: 3
• Three Forks, second bench: 6

Earlier posts:

• August 31, 2017;
• June 11, 2017;

*****************************
Photos

A reader was kind enough to send a photo of the 17-well Simmental pad -- this picture looks west-to-northwest toward Williston. Isn't it just a superb picture of North Dakota? I just love it.

Think about it. Seventeen wells, $10 million each just to get started -- $170 million pad and on-going operational costs. Big, big, big business.

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

The Graphics

September 15, 2020:

January 8, 2020:

Original post:

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

On Fire

BR Looks To Put 20 Wells On A 2560-Acre Unit In Pershing/Johnson Corner -- October 26, 2019

From the November, 2019, NDIC hearing dockets, case #28116, not a permit, but a case:

28116, BR, Pershing-Bakken, 20 wells on a 2560-acre unit; sections 16/21/28/33-150-96; McKenzie

Well in the drilling unit and immediate area:

• 23622, 1,225, Abraxas, Lillibridge 20-17-1H, Pershing, t7/13; cum 449K 8/19;

• 343285, 718, Abraxas, Lillibridge 20-17-9H, Pershing, t9/18; cum 134K 8/19;

• 29805, 802, BR, Morgan 14-21TFH ULW, Pershing, t11/15; cum 115K 8/19;
• 29867, 3,126, BR, Kirkland 14-21TFH ULW, Pershing, t10/15; cum 565K 8/19; huge jump in production 4/19, but great production from day one;
• 29804, 2,806, BR, Kirkland 14-21MBH, Pershing, t11/15; cum 319K 8/19;
• 29803, 2,325, BR, Morgan 14-21MBH, Pershing, t11/15; cum 258K 8/19;

• 29795, 1,283, BR, Morgan 24-21TFH, Pershing, t1/16; cum 153K 8/19;
• 29796, 1,723, BR, Kirkland 24-21MBH, Pershing, t12/15; cum 284K 8/19;
• 29797, 2,084, BR, Morgan 24-21MBH, Pershing, t12/15; cum 253K 8/19;

• 22791, 2,084, BR, Morgan 21-28TFH 3NH, Pershing, t1/13; cum 194K 8/19;
• 22792, 2,926, BR, Kirkland 21-28TFH 3SH, Pershing, t1/13; cum 285K 8/19;
• 22790, 2,325, BR, Kirkland 21-28MBH 2SH, Pershing, t1/12; cum 34K 8/19;
• 22789, 2,004, BR, Morgan 21-28MBH 2NH, Pershing, t1/13; cum 262K 8/19;

• 17529, 300, BR, Morgan 34-21H, Pershing, t2/09; cum 334K 8/19;

• 29872, 1,443, BR, Kirkland 41-28TFH, Pershing, t11/15; cum 210K 8/19;
• 29873, 2,084, BR, Kirkland 41-28MBH, Pershing, t11/15; cum 322K 8/19;
• 29874, 2,004, BR, Morgan 41-28MBH, Pershing, t12/15; cum 280K 8/19;
• 29875, 1,483, BR, Morgan 41-28TFH ULW, Johnson Corner, t11/15; cum 262K 8/19;

• 28272, 2,685, BR, Copper Draw 11-27TFH ULW, Pershing, t11/14; cum 264K 8/19;

• 17292, 765, BR, Kirkland 1-33H, Pershing, t10/08; cum 238K 8/19;

• 34058, 541, BR, Kermit 8-8-32MBH, Pershing, t8/18; cum 163K 8/19;

Graphic:

November, 2019 Hearing Dockets: BR To Request 20 Wells In One 2560-Acre Stand-Up Unit -- Middle Bakken And First Bench Only -- October 25, 2019

From the NDIC, November, 2019, hearing dockets:

• 28117, BR, Johnson Corner and/or Pershing-Bakken, twenty (20) wells on a 2560-acre unit, section 15/22/27/34 -150-96; McKenzie County

Thinking out loud:

• currently nine horizontals running north in a 1280-acre unit
• currently nine horizontals running south in a 1280-acre unit
• plan for ten more horizontals running north through those two sections: a total of 19 horizontals running north (but the new wells will be spaced at 2560-acre spacing)
• plan for ten more horizontals running south through those two sections: a total of 19 horizontals running south (but the new wells will be spaced at 2560-acre spacing)
• these are all middle Bakken and first bench Three Forks wells
• lower benches of the Three Forks yet to targeted (may or may not happen)
• many, many ways to look at density
• one way: 1280 acres / 19 wells = 67 acres (MB and TF1 combined)
• another way: 1280 acres / 10 wells = 128 acres (MB or TF1 separately)
• another way: vertical array of 19 horizontals is still less than the 24 or more that some have proposed
• another way: spacing between horizontals, horizontally: 5280 feet / 10 wells = ~ 500 feet
• note: about two years into blogging about the Bakken I opined that fracking was effective out to 500 feet radially; something tells me I may be off by a factor of 2 before this is all over

Wells in the graphics (not all wells are in these 1280-acre or 2560-acre spacing units; some of the wells below lie outside these spacing units):

• 17529, 300, BR, Morgan 34-21H, Pershing, t2/09; cum 335K 7/19; off line as of 7/19; remains off line 8/19;

• 29872, 1,443, BR, Kirkland 41-28TFH, Pershing, t11/15; cum 201K 8/19;
• 29873, 2,084, BR, Kirkland 41-28MBH, Pershing, t11/15; cum 322K 8/19;
• 29874, 2,004, BR, Morgan 41-28MBH, Pershing, t11/15; cum 201K 8/19;
• 29875, 1,483, BR, Morgan 41-28TFH ULW, Pershing, t11/15; cum 262K 8/19;

• 28272, 2,685, BR, Copper Draw 11-27TFH ULW, Pershing, t11/14; cum 264K 8/19;
• 28273, 2,445, BR, Copper Draw 11-27MBH, Pershing, t11/14; cum 397K 8/19;
• 28274, 2,485, BR, Lillibridge 11-27MBH NH, Johnson Corner, t10/14; cum 238K 8/19;

• 27306, 1,523, BR, Lillibridge 21-27TFH, Johnson Corner, t10/14; cum 242K 8/19;
• 27307, 2,244, BR, Copper Draw 21-27MBH, Johnson Corner, t10/14; cum 339K 8/19;
• 27308, 1,683, BR, Lillibridge 21-27MBH, Johnson Corner, t9/14; cum 192K 7/19; off line as of 7/19; remains off line 8/19;
• 27309, 2,004, BR, Copper Draw 21-27TFH, Johnson Corner, t10/14; cum 300K 8/19;

• 23648, 2,725, BR, Copper Draw 24-22MBH, Johnson Corner, t7/13; cum 326K 8/19;

• 23647, 2,886, BR, Lillibridge 24-22TFH, Johnson Corner, t7/13; cum 295K 8/19; off line as of 7/19; remains off line 8/19;
• 23646, 2,325, BR, Copper Draw 24-22TFH 2SH, Johnson Corner, t7/13; cum 302K 8/19;
• 23645, 2,926, BR, Lillibridge 24-22MBH 2NH, Johnson Corner, t7/13; cum 375K 8/19;

• 28348, 1,920, BR, Copper Draw 41-27TFH, Johnson Corner, t3/15; cum 276K 8/19; off line as of 7/19; remains off line 8/19;
• 28347, 1,656, BR, Lillibridge 41-27MBH, Johnson Corner, t3/15; cum 330K 8/19;
• 28346, 2.400, BR, Lillibridge 41-27TFH-ULW, Blue Buttes, t3/15; cum 437K 8/19;
• 28345, 2,880, BR, Copper Draw 41-27MBH-ULW, Croff, t4/15; cum 513K 8/19;

• 17271, 312, BR, Copper Draw 34-34H, Blue Buttes, t6/08; cum 480K 8/19;

• 17323, 110, BR, Mary Ann 1-15H, Johnson Corner, t8/08; cum 467K 8/19;

The graphics:

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

"Parent-Well-Uplift" And Infill Density -- May 10, 2019

This is really, really cool.

The "mainstream" analysts are catching up with two phenomena in the Bakken that we've been discussing for a long, long time: the "halo" effect" and infill density.

For recent commentary on the former, see this link.

For infill density, see this screenshot from twitter today:

Wow, CLR brought up this issue years ago and I've posted too-many-to-count graphics on infill density -- years ago. And now we're starting to see "mainstream" analysts do some good statistical research.

For newbies, this was the concern: that daughter wells -- new wells -- would diminish, negatively impact, even perhaps "ruin" existing wells, or "parent wells. I think a lot of folks in North Dakota at the beginning of the boom expected to see one well in every section (640 acres). Many were surprised to see as many as four in a one-mile square, but then to see reports that there could be as many as 24 wells (or more) in a 1280-acre drilling unit was beyond the pale.

Folks with nice wells were legitimately concerned that new wells placed too closely to these existing nice wells would "hurt" the old wells.

Anecdotally, I was seeing just the opposite and I posted any number of blogs about that.

Now we have a "professional" providing more than just anecdotal evidence.

Look at that graphic. We're talking 660'-spacing. Instead of placing horizontal wells one mile apart, operators are seeing no adverse impact even placing the wells 660 feet apart.

In fact, if one looks closely, the daughter wells are doing slightly better than parents wells but I doubt this is statistically significant. Without seeing the study itself, I assume this is from the Permian. Z4 tags "JAG" -- a Permian operator.

Hey, by the way, look at the EUR of those JAG wells: 1.21 million boe. 

Wow, I can't remember how many years ago -- maybe 2009, 2010 -- I noted that fracking was effective 500-feet radially -- meaning that horizontals could be placed 500 to 1,000 feet apart. I may have this wrong, but at 660-feet spacing, if the horizontals are 660 feet from each other, it suggests fracking is most effective 330-feet radially. We're talking horizontal through the seam because vertically things are affected by different geology: dolomite (sand) in the producing seam; shale (rock) in the generating seams.

MROs Higher Density Pilots -- December 21, 2014

Back in January, 2014, I posted links to CLR's density projects.

A reader sent me the link to MRO's recent corporate presentation. Marathon also has four (4) operated high density pilots in three major areas: its Myrmidon, Hector, and Ajaz prospects. From my "Snapshot" page:

• Myrmidon: northwest corner of the reservation
• Marfa: MRO's largest area; southwest of the reservation; borders the reservation, Dunn County -- Marfa DOES NOT show up on most recent presentation
• Hector: eastern area of Marfa, just outside of the reservation, Dunn County
• Ajax: continuation of Marfa, southwest of Marfa, Dunn County

Myrmidon:

• Brodahl Pilot: 6 x MB; 6 x TF1, 4Q14 spud
• TAT USA 34 Pilot: 6 x MB, 6 x TF2, 6 x TF2, 1Q15 spud

Hector:

• Lucy Fleckenstein Pilot: 6 x MB, 6 x TF1, spud August 2014

Ajax:

• Hecker Pilot: 6 x MB, 4Q14 spud

By the way, if you do visit slide 14 at the linked presentation above, the slide says the Myrmido IRR is greater than 60% BFIT.  BFIT: Profit is the amount of revenue remaining after payment of royalty, operating costs, investments, and taxes, including income taxes. A distinction is often made between before-income tax (BFIT) profit and after-income tax (AFIT) profit for analysis purposes.

A Random Look At The 2560-Acre Unit In Which CLR Will Place 28 Wells -- November 22, 2014

Updates

June 13, 2022: some Florida Federal wells have been updated. These are very, very good wells.

February 2, 2020: update of a few Florida Federal wells. 

January 7, 2020: production data and graphics updated. Updated graphic of the area:

August 19, 2019: production data and graphics updated.

October 28, 2018: see production profile for this amazing well, #21977. 

June 26, 2017: new wells --

• 32476, drl-->drl/NC, CLR, Florida Federal 6-11H1, Camp, status noted 10/19;
• 32474, drl-->drl/NC, CLR, Florida Federal 7-11H, Camp, status noted 10/19;
• 28806, PNC, CLR, Florida Federal 6-11HPNC, Camp,

Original Post
 

In the December, 2014, NDIC hearing dockets, CLR wants to put 28 wells in one 2560-acre drilling unit.  

So, where is the 2560-acre unit which which CLR is requesting 28 wells? This is the case, not a permit:

• Case 23454, CLR, Camp-Bakken, 28 wells on an existing 2560-acre unit, McKenzie, Williams

This is the 2560-acre spacing unit: sections 2, 11, 14 and 23, T.152N.R.100W.

Right now, there are 12 wells/permits in that drilling unit:

-- in section 14, six completed wells, 2560-acre spacing:

• 21977, 1,016, CLR, Florida 3-11H, 38 stages, 3.4 million lbs, t1/13; cum 643K 8/20; huge jump 3/17;
• 21979, 338, CLR, Alpha 3-14H, t1/13, 26 stages, 2.3 million lbs; cum 373K 8/20;
• 21980, 569, CLR, Florida 1-11H, Three Forks, 38 stages, 3.4 million lbs, t1/13; cum 283K 8/20;
• 21981, 377, CLR, Alpha 1-14H, 26 stages, 2.3 million lbs, t1/13; cum 152K 8/20;
• 21982, 706, CLR, Florida 2-11H, 38 stages, 3.4 million lbs, t2/13; cum 424K 8/20;
• 21983, 504, CLR, Alpha 2-14H, 30 stages; 2.8 million lbs sand/ceramic, t2/13; cum 312K 8/20;

-- in section 14, six wells on confidential status, 2560-acre spacing?

• 28805, PNC, CLR, Alpha 6/14H,
• 28804, PNC, CLR, Florida Federal 6-11H,
• 28803, 1,338, CLR, Alpha 5-14H, Camp, 4 sections, 20 stages, 9.9 million lbs, t3/17; cum 273K 8/20;
• 28802, 190, CLR, Florida Federal 5-11H2, Camp, 4 sections, 16 stages, 5 million lbs; 16 of 45 zones planned for this well; will resume operations when plug and guns are fished out of this well; well not producing (4/17); t3/17; cum 150K 8/20; off line 2/20; remains off line 4/20;
• 28801, 1,194, CLR, Alpha 4-14H1, Camp, 4 sections, 20 stages, 9.6 million lbs, t3/17; cum 210K 8/20;
• 28800, 1,386, CLR, Florida Federal 4-11H1, Camp, 4 sections, 45 stages, 22 million lbs, t3/17; cum 426K 8/20; update here; a huge well;

It is likely that we could see 16 more wells in this section, 8 running north, 8 running south; half targeting the middle Bakken, half targeting various benches of the Three Forks.

It is interesting: in this area, it is all 1280-acre spacing with two exceptions:

• one 2560-acre unit
• one 1600-acre unit:

The graphics:

August 19, 2019:

 Original graphic:

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

CLR's Bakken Density Pilot Project Update -- 2Q14 Earnings Press Release -- August 5, 2014

Press release here.

In 2013, the Company embarked on a plan to test different areas across the Bakken field to determine what well density and pattern best maximizes crude oil recovery and returns.  In all, the Company has initiated seven density pilot projects, all designed to include the Middle Bakken and Three Forks One, Two and Three ("TF1", "TF2", "TF3") across a broad section of Continental's approximately 1.2 million net acres of leasehold.  Three of these projects are testing 1,320-foot inter-well spacing and four are testing 660-foot inter-well spacing.  [I assume the "old" "upper Three Forks" is now TF1.]

The Hawkinson 1,320-foot pilot project was the first to be completed by the Company and was announced as a fourth quarter 2013 completion, followed by additional 1,320-foot spacing tests at the Rollefstad and Tangsrud units.  The Hawkinson pilot continues to be a strong producer with all of the 14 wells trending on average 50% above the Company's 603,000 Boe EUR model after 190 to 250 producing days. 

The Rollefstad pilot is also performing well, with 10 of the 11 wells on the unit producing an average rate that is 10% above the 603,000 Boe EUR model after approximately 60 producing days.  Four wells at the Rollefstad unit are still flowing naturally without the aid of artificial lift. 

The Tangsrud pilot was designed to test the extent of the Lower Three Forks productive footprint in the northern portion of the play.  On average the MB and TF1 wells are producing similarly to neighboring wells in the area.  The TF2 and TF3 producers in the Tangsrud pilot continue to underperform offset MB and TF1 producers and do not appear to deliver economic results that compete with the Company's substantial inventory of high rate-of-return development opportunities, based on current technology and cost structure. 

In late May 2014, the Company began producing its first 660-foot inter-well spacing test at the Wahpeton pilot in McKenzie County, North Dakota.  The new wells were completed using the Company's standard completion design of 30 stages with 100,000 pounds of proppant per stage.  Initial production rates for the 12 new wells in the unit averaged approximately 1,015 Boe per day, which included three new MB wells averaging approximately 1,730 Boe per day.  

Mr. Bott added, "Continental continues to lead the industry in seeking the optimum density and enhanced completions in order to maximize recovery, enhance returns and increase net present value.  It is too early to estimate recoveries at the Wahpeton pilot; however, we are encouraged by the early performance and potential for 660-foot inter-well spacing."

The three remaining pilot projects are 660-foot inter-well spacing tests that are in various stages of drilling or completion.  These include the Mack, Lawrence and Hartman units, which include a combined 18 new wells and six existing producers.  The new wells are expected to be completed in the second half of 2014.

CLR's Increased Density Projects

Hawkinson
Tangsrud
Rollefstad
Wahpeton
Hartman
Mack
Lawrence

Interestingly, the 30 Jersey/Jersey Federal wells are not designated increased density pilot projects; nor is the Atlanta pad in Baker oil field, McKenzie County.

For Newbies: A Quick Look Where the Bakken Is Headed: S T A G G E R I N G

Link here.  (regional links break early and break often)

How many wells in a 1280-acre spacing unit: the number could be in the teens -- Director, NDIC.

In fact, Helms says the state just issued a permit for the largest drilling pad in the state history - a pad to allow many wells at one site.

"We just permitted for Contininental Resources the largest oil pad we've permitted so far just outside of Williston, it's got 14 wells and will extract the oil from the Missouri River bottoms where there was flooding last year."

A bit of inconvenience for awhile:

He admits that for the people living along a road where there once was one well and will someday be a dozen or more are going to be unhappy with the thousands of trucks that'll have to travel that road. But he says the bigger picture is that the state will be able to keep multiplying its oil production while keeping the adverse impact on the countryside as small as possible.

This is from today's posting of what operators are asking to drill in the future:

• 18670, CLR, Oakdale-Bakken, 18 wells on each existing 1280-acre unit; Dunn
• 18671, CLR, Elm Tree-Bakken, 18 wells on each existing 1280-acre unit; McKenzie
• 18672, CLR, Antelope-Sanish, 18 wells on an existing 1280-acre unit; McKenzie
• 18621, Hess, Alkali Creek-Bakken, 10 wells on each 1280-acre unit, and 20 wells on each 2560-acre; McKenzie, Mountrail, Williams
• 18622, Hess, Robinson Lake-Bakken, 10 wells on each 1280-acre unit, and 20 wells on each 2560-acre; McKenzie, Mountrail
• 18623, Hess, Alger-Bakken, 10 wells on each 1280-acre unit, and 20 wells on each 2560-acre; McKenzie, Mountrail
• 18624, Hess, Manitou-Bakken, 10 wells on each 1280-acre unit; Mountrail, Williams
• 18625, Hess, Big Butte-Bakken, 10 wells on each 1280-acre unit; Mountrail
• 18626, Hess, Baskin-Bakken, 10 wells on each 1280-acre unit; Mountrail
• 18627, Hess, Beaver Lodge-Bakken, 10 wells on each 1280-acre unit;  Williams
• 18628, Hess, Capa-Bakken, 10 wells on each 1280-acre unit; Williams18629, Hess, Hofflund-Bakken, 10 wells on each 1280-acre unit; Williams, McKenzie 
• 18781, EOG, Squaw Creek-Bakken, 3 wells on each existing 320-acre unit; McKenzie; this translates to 6 wells on a section -- remember, at one time, folks in Williston were talking about one (1) well in each section would be exciting

By the way, I've argued that larger spacing units are good for everyone. When I took a poll, I was in the minority. Maybe some day I will get around to explaining why larger spacing units are good for everyone. My assumption is that over time, folks will figure it out for themselves.