BR With Permits For A 7-Well Sequoia-Well-Infill Pad -- June 5, 2020

BR with seven new permits, #37614 - #37620, inclusive --

• BR has permits for a seven-well Sequoiafill pad in SWSE 36-153-95, Hawkeye oil field; all 870’ FSL and lined up east-west about 2600' FWL

The graphic:

The wells identified in the graphic above:

• 26598, 1,923, BR, Sequoia 14-9TFH, Hawkeye, t8/14; cum 315K 4/20;
• 26599, 1,923, BR, Sequoia 14-9MBH, Hawkeye, t8/14; cum 340K 2/20; off line 2/20; remains off line 4/20; 
• 26600, 1,923, BR, Sequoia 24-9MBH, Hawkeye, t8/14; cum 268K 4/20;
• 18140, 540, BR, Sequoia 24-9H, Hawkeye, t9/09; cum 308K 4/20; see full production profile at this post;

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:

Damn The Torpedoes, Full Speed Ahead -- CLR -- February 5, 2020

Updates

April 11, 2022: production updates. 

March 17, 2021: the Gordon Federal pad, "today":

February 22, 2021: yesterday I noted a number of Gordon Federal permits "expired." Tonight I noted on the daily activity report that four of those "expired" permits were renewed.

Original Post

CLR has just renewed twelve Gordon Federal permits.

Some observations.

First: note all the "white space." Lots and lots of work that needs to be done in the Bakken. In addition, most of those horizontals in the graphics below were completed using "old" completion strategies. These wells will all be re-fracked and/or re-drilled/re-fracked.

Certainly the interest for twelve more Gordon Federal wells is not in one tiny sweet spot surrounded by a dearth of oil in neighboring sections.

I don't follow the Permian, but what little I read suggests operators are still being challenged by the size of drilling units in the Permian, and are still flummoxed by the optimum spacing. From what I see, and I follow it pretty closely, it appears operators in the Bakken have solved one of the issues; and, having little trouble with the other issue.

Again: the ovals highlight all the "white space." Lots of work yet to be done in the Bakken. In most of the Bakken, the minimum number of wells in any 1280-acre drilling unit: eighteen wells. But it may be decades before we get to that density. Eighteen wells: middle Bakken; Three Forks, 1st bench; Three Forks; deeper benches; Sanish in some areas. When I first started blogging, I said that if a mineral owner had one well, that mineral owner would eventually have four wells, probably eight wells; possible twelve wells, and maybe many, many more than that.

Currently: seven horizontals shown. Two huge pads being developed. Only two formations are being targeted, right now.

12-well pad:

11-well pad:

The wells:

• 16683, 224, CLR, Federal Jorgenson 14-5H, Haystack Butte, t12/07; cum 70K 11/19;

• 36107, loc-->EXP-->renewed, CLR, Gordon Federal 1-5H, Haystack Butte, 2560-acre; 4/5/8/9-148-87; middle Bakken; renewed February 22, 2021; see this note;
• 36106, loc-->EXP-->renewed, , CLR, Gordon Federal 2-5H1, Haystack Butte, 2560-acre; 4/5/8/9-148-87; Three Forks B1; enewed February 22, 2021; see this note;
• 36105, loc-->EXP, CLR, Gordon Federal 3-5H, Haystack Butte, 2560-acre; 4/5/8/9-148-87; middle Bakken; see this note;
• 36104, loc-->EXP-->renewed, CLR, Gordon Federal 4-5H1, Haystack Butte, 2560-acre; 4/5/8/9-148-87; Three Forks B1; renewed February 22, 2021; see this note;
• 36103, loc-->EXP-->renewed, CLR, Gordon Federal 5-5H, Haystack Butte, 2560-acre; 4/5/8/9-148-87; middle Bakken; renewed February 22, 2021; see this note;
• 36102, loc-->EXP, CLR, Gordon Federal 6-5H1, Haystack Butte, 2560-acre; 4/5/8/9-148-87; Three Forks B1; first production, 10/21; t--; cum 112K 2/22; see this note;
• 36101, loc-->EXP-->loc, CLR, Gordon Federal 7-5H, Haystack Butte, 2560-acre; 4/5/8/9-148-87; middle Bakken; bottom hole, 4-148-97; see this note;
• 36100, loc-->EXP-->PNC, CLR, Gordon Federal 8-5H1, Haystack Butte, 2560-acre; 4/5/8/9-148-87; Three Forks B1; first production, 10/21; t--; cum 63K 2/22; see this note;
  
• 36099, 2,022, CLR, Gordon Federal 9-5H, Haystack Butte, 2560-acre; 4/5/8/9-148-87; middle Bakken; 9.94 million lbs proppant, 37 stages; first production, 11/20; t--; cum 106K 1/21; cum 187K 2/22;
  
• 36098, 2,055, CLR, Gordon Federal 10-5H1, Haystack Butte, 2560-acre; 4/5/8/9-148-87; Three Forks B1; producing; big well; 9.97 million lbs proppant; 37 stages; first production, 11/20; t--; cum 89K 1/21; cum 200K 2/22;
  
• 36097, l,502, CLR, Gordon Federal 11-5H, Haystack Butte, 2560-acre; 4/5/8/9-148-87; middle Bakken; producing; nice well; 9.98 million lbs proppant; 37 stages; first production, 11/20; t--; cum 84K 1/21; cum 199K 2/22;
  
• 36096, 2,117/F/A, CLR, Gordon Federal 12-5H1, Haystack Butte, first production, 11/20; t--; cum 76K 1/21; fracked, 3/1/20 - 3/9/20; 8.4 million gallons of water; 87.4% water by mass; 37 stages; target: Three Forks first bench; within CLR's Rocket prospect; cum 241K 2/22;
  

• 36054, 2,419/F/A, CLR, Gordon Federal 13-8H, Haystack Butte, 2560-acre; 4/5/8/9-148-87; middle Bakken; spud, July 30, 2019; cease drilling, October 16, 2019; bottom hole, 9-148-97; 9.7 million lbs proppants; 36 stages; first production, 11/20; t--; cum 78K 12/20; cum 235K 2/22;
  
• 36055, 1,893/F/A, CLR, Gordon Federal 14-8H1, 33-025-03678, Haystack Butte, first production, 11/20; t--; cum 51K 1/21; 9.99 million lbs proppant; 37 stages; thirteen hours to build the curve; four days to drill the lateral; Three Forks B1 at 11,626' MD; cum 181K 2/22;
  
• 36056, 1,907/F/A, CLR, Gordon Federal 15-8H, 33-025-03679, Haystack Butte, first production, 11/20; t--; cum 100 1/21; 10.07 million lbs proppant; 37 stages; fifteen hours to drill the curve; three days to drill the lateral; cum 269K 2/22;
  
• 36057, loc, CLR, Gordon Federal 16-5H1, Haystack Butte,
• 36058, loc, CLR, Gordon Federal 17-8H, Haystack Butte,
• 36059, loc, CLR, Gordon Federal 18-5H1, Haystack Butte,
• 36060, loc, CLR, Gordon Federal 19-8H, Haystack Butte,
• 36061, loc, CLR, Gordon Federal 20-5H1, Haystack Butte,
• 36062, loc, CLR, Gordon Federal 21-8H, Haystack Butte,
• 36063, loc, CLR, Gordon Federal 22-5H1, Haystack Butte,
• 36064, loc, CLR, Gordon Federal 23-8H, Haystack Butte, 

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:

A Look At 30 Horizontals In A Single Section In The Elm Tree Oil Field -- October 8, 2019

From today's daily activity report:

Eight new permits, #37053 - #37060, inclusive;

• Operator: CLR
• Fields: Elm Tree (McKenzie)
• Comments: 
• CLR has permits for an 8-well Angus Federal pad in SENW section 

Adding those eight locations to the previous activity, this is what the area now looks like:

In that immediate area, just looking at one section:

• five horizontals; producing wells, including the section line well (#33964)
• ten Simmental Federal / Charolais South Federal permits
• eight Angus federal permits
• seven wells on the confidential list
• total: 30 locations/wells

This is starting to become overwhelming. 

"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.

Is QEP Ready To Exit The Bakken? Focus On The Permian? QEP With Successful Re-Frack Program In The Bakken -- March 31, 2018

Disclaimer: this is not an investment site. Do not make any investment, financial, job, travel, or relationship decisions based on anything you read here or think you may have read here. If this is important to you, go to the source.

Note: in a long note like this, there will be factual and typographical errors. Comments and opinions may be interspersed with factual notes. 

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

Earnings Call: QEP

4Q17

From the earnings call, 4Q17, QEP, over at SeekingAlpha:

• earnings:
• 4Q17: $195 million
• 3Q17: $193 million
• 4Q16: $175 million
• production:
• 4Q17: 12 million boe (decrease primarily due to the Pinedale divestiture in 3Q17
• 3Q17: 14 million boe (Pinedale: contributed 3 million boe)

Excerpts and data points from the earnings call follow.

Fracking

• Williston oil volumes were up about 334,000 barrels due to our refrac program
• in the Williston Basin, we began our refrack program using a design which was closely patterned after the successful methodology that we are utilizing in our Haynesville wells. As a reminder, because of well spacing in the Williston, we have to shut in offset wells during these refracs and also obviously during new well completions, which has a negative impact on production volumes. While we're still fine-tuning our re-frack design, we're very encouraged by the early results, and we look forward to continuing the program in 2018. 
• see this post for random look at jump in production suggesting re-frack

LOE:

• On a per unit basis, lease operating expenses were $6.58 per boe, which is up $1.19 per boe from the third quarter due to higher workover and repair expenses, primarily in the Williston Basin

CAPEX:

• capital expenditures on an accrual basis for E&P activities in the fourth quarter were $372 million, an increase of about $45 million from third quarter
• CapEx in the Permian Basin was $215 million which included $18.9 million from midstream infrastructure
• CapEx in the Williston Basin was about $88 million
• CapEx in Haynesville was about $58 million.

Conversion from natural gas to liquids:

Through a series of acquisitions and two world-class oil provinces, first, in the Williston Basin, and then in the Permian, and through divesture of non-core gas-weighted assets in the Midcontinent and the Rockies, we successfully increased liquids from less than 15% of total production in 2011 to almost 50% last year.

Comment: this has been quite a ride watching this company. I remember when it entered the Bakken -- acquiring the "holy Grail/Helis Grail" and wondering how a "natural gas company" would do in an oily play. To say the least: I am more than impressed.

If there was one disappointment for the company: the failure to unitize the Grail oil field. I think royalty owners did themselves and QEP a "disservice" (if that's the best word) when they voted against unitization.

Exiting the Bakken:

• we plan to return cash to shareholders through a significant share repurchase program

So, how are we doing it? We outlined a couple of strategic initiatives. First, we've engaged financial advisors to assist us in the divesture of our Williston and Uinta Basin assets.

And when I say Williston assets, obviously there's two assets: there's a South Antelope asset and the Fort Berthold asset. We'll present those as two separate packages, but obviously, we'll allow bidders to make offers on the one or both of those assets. And we also will have an advisor engaged to divest at our Uinta Basin assets. 

Focus on the Permian:

We also announced a number of financial initiatives. First, we plan to use the proceeds from asset sales to fund development of our Permian properties until the program reaches operating cash flow neutrality, which we expect to occur in 2019. 

Frack spreads:

• on the 95 Permian completions in 2018, how many frac crews do you need to operate that plan?
• We'll average two. We may pick up an occasional third crew, but our frack efficiency is quite good.

Tank-style development of the Permian

• look at the slides below and read the conference call notes describing these slides
  
• go to the QEP website
• go to "slides" (I assume this presentation will disappear over time)
• slides 11 - 13 are the core of the "tank-style" development discussion

Filloon Updates Chevron Completions -- January 21, 2018

In the article linked below, the most important thing that jumps out at me: 

Operator production improvements have occurred consistently since 2014. This is when operators began to focus in better fracturing near the well bore. 

This tells me exactly what I've thought all along; 500-ft radially from the wellbore is probably the max efficiency for fracking which means increased density of wells in any given drilling unit.

Over at Seeking Alpha.

Well design is driving oil production gains for US E&Ps. Oil prices have improved as world inventories decrease. Improved well design is lowering breakevens, and economic improvements should continue in 2018. Better source rock stimulation has increased oil production per foot. We have not seen this leveling out, which seems to support the hypothesis of further improvements going forward. This may lead to increased US production, but higher prices will be needed to stimulate meaningful growth. Increased production could place a ceiling on oil prices. We think demand will more than offset US production in 2018.

Chevron has a relatively large acreage positions in the Permian. This is important as the Midland and Delaware Wolfcamp will fill much of the supply decreases from current world oil legacy projects.

The Bakken and Eagle Ford will also be involved, but West Texas is currently the best place to be. We pulled 116 horizontal completions done in 2016 and later. 53 laterals were 6,000 feet or less. The graph below plots oil production over the life of each well. Locations that have been online over a shorter period of time are producing much better.

CVX is at the lower end of production improvements when compared to other operators in the Permian. CVX has used more one mile laterals. Production improvements based on feet, have CVX closer to the average.

CVX should do very well in 2018. Operator production improvements have occurred consistently since 2014. This is when operators began to focus in better fracturing near the well bore. It is a change from longer laterals (more feet), to better stimulation (focus on more oil per foot).

WTI At $52.68; Statoil Looks At $27 Breakeven In The Eagle Ford -- October 26, 2017

Note: the Freedom Energy well targeting the Lodgepole southwest of Dickinson, #33997, has been updated at this post. 

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

Breakeven Costs (Again)

Tea leaves: it's really, really "fun" to watch for "red flags" (good and bad) buried in long, long reports. I did not catch this the first I went through the earnings report, but look at the breakeven target that Statoil wants in the Eagle Ford in their "next generation" wells in the Eagle Ford: $27 oil. Is that far-fetched? Is anyone else talking about $30 oil? If one is paying attention, we talked about it  -- was it yesterday -- let's look: yes, here it is, yesterday: "Big Oil target: make money at $30-oil." -- Bloomberg

This has so many incredible implications -- making money at $30 oil. But time to move on.

Statoil earnings cal, 3Q17: link here. From Q&A:

Q: ... some of your competitors called things like train wreck wells with that tighter down spacing in Eagle Ford and whether there's some extra CapEx that will drop out and not be spent going forward?
A: ... on the well spacing and the change of CapEx, it's too early to conclude, we have changed the well spacing to a wider space of 500 feet
Q: ...related to the Eagle Ford downgrade, I think there's some concern in the market over your relatively low reserve life. I'm guessing that's going to fall further on the back of the Eagle Ford downgrade to reserves. So just how you're kind of thinking about that reserve life within that context as well?
A: (does not answer the question; too early to tell) ... In terms of reserve life, on a portfolio level, we like to talk about the next generation portfolio with an excellent breakeven, it's $27 on average, short payback time 2023, IRR 20%, you heard me say this before. So we're not worried about that. On Eagle Ford, this is part of what we are assessing based on the change and the improvement work we're doing.
Q: ... impairments
A: ...The largest impairment of $0.85 billion is specifically on Eagle Ford. This was triggered by lower than expected production volumes, but the impairment in itself is calculated based on our market valuation.
Q: ... impairments
A: ... So the history we're coming from is that both in this quarter and in previous quarters, we've had impairments and reversals. And the largest one in this quarter is Eagle Ford. So, this is due to the trigger of reduced production rates. As part of the industry, we started a year ago to do tighter well spacing 200 feet to 250 feet. We had great faith in this measure of course, so we actually reversed based on the plans and the indicative results, that didn't turn out to be as favorable as we hoped for. So we have, of course, stopped that practice and are changing it.
This is an Eagle Ford issue as it has been for the industry with tighter well spacing. So based on that, we did a valuation, third-party market assessment and we have started working out an improvement plan. So, we have moved from 200 feet to 250 feet well spacing to 500 feet. Very early days, too early to conclude, but the indicative result so far is in the positive direction. So, this is something we will come back to. So, as I said, there is uncertainty in valuation and reserves. So that's why we have these changes

From the blog, July 26, 2017 (link here):

I've also read that some operators in the Bakken can meet their 2017 contractual agreements in the first six months of the year. Anyone following "wells of interest" can understand why I say that "new" bbls in the Bakken are being lifted for a lot less than $28/bbl, using OXY's accounting methods.

 **********************************

Back To The Bakken

Active rigs:

$52.68↑	10/26/2017	10/26/2016	10/26/2015	10/26/2014	10/26/2013
Active Rigs	53	36	68	194	182

Eight (8) new permits:

• Operators: Hess (6); BR; Ballard Petroleum
• Fields: Blue Buttes (McKenzie); Camel Butte (McKenzie); Wildcat (Bottineau)
• Comments: Hess has permits for a 6-well BB-Chapin pad in section 5-151-95

CLR renewed four permits:

• CLR: two Charlotte permits; one Chicago permit; and, one Akron permit, all in McKenzie County

Five permits canceled:

• EOG (3): two Mandaree permits and one West Clark permit, all in McKenzie County
• HRC: one Fort Berthold permit, in McKenzie County
• Oasis: one Crane Federal permit in Williams County

One DUC reported as completed:

• 33499, 593, Oasis, Osprey5401 44-23H, Todd, t10/17; cum --

The Number Of Bakken Wells Producing Over 30,000 Bbls/Month Continues To Increase -- October 14, 2017

A reader sent this note (slightly edited) regarding North Dakota Bakken production in August, 2017:

Based on the monthly production in the general statistics section of the NDIC O&G web page, these observations:

There were 66 wells in August that produced over 30,000 bbls of oil in the month. 

In August the top three wells were by Marathon; the next 3 by EOG. Marathon didn’t used to be known for high production rates from their wells as I recall? I don’t know how these wells compare to wells in other basins but these look pretty amazing.

I listened to the 8-9-17 conference call with CLR and they were pretty upbeat about the Bakken it seemed to me. They were very happy with the new enhanced completion techniques they were using. I think they said for one thing with the new technology they may have to revisit the proper spacing on the wells.

I think they are getting a lot more results close to the well bore and the frac jobs are not penetrating as deep. Seems that would be reflected in the halo affect? And they also suggested the area they consider to be core is growing with these better rates and all of their property will benefit from enhanced completion techniques and make those areas profitable at prices lower than previously thought.

See this post, also. 

I think the comment regarding infill density is the most interesting. Stay tuned.

Five DUCs Reported As Completed -- May 9, 2017

Active rigs:

$46.03	5/9/2017	05/09/2016	05/09/2015	05/09/2014	05/09/2013
Active Rigs	50	28	84	192	183

Four new permits:

• Operator: CLR
• Field: Elm Tree (McKenzie)
• Comments: NESE 25-153N-94W (see graphic below)

Fourteen permits renewed:

• Enerplus (12): Axe, Poblano, Vise, Cayenne, Anvil, Habanero, Calico, Bengal, Manx, Tabby, Siamese, and Persian permits renewed, all in Dun County
• Oasis (2): two Hanover Federal permits renewed

Five producing wells (DUCs) reported as completed:

• 14898, 279, Newfield, Gohrick 1, Helle Slough, t5/99; cum 127K 3/17; (we'll get back to this later)
• 29477, 970, CLR, Kukla 5-16H11, Chimney Butte, t5/17; cum -- (17398)
• 30512, 3,255, MRO, Gaynor 34-33H, Reunion Bay, t2/17; cum 53K 3/17; (18191: see this post)
• 30513, 2,830, MRO, Anton 34-33TFH, Reunion Bay, t2/17; cum 3K 3/17; (18191)
• 31849, 2,470,  MRO, Ronald 34-33TFH-2B, Reunion Bay, t2/17; cum 29K 3/17;(18191)

********************* 

If You Have One Well, You Will Probably Have Twelve 

Typo in graphic ("wels") noted; not gonna fix it.

Petro-Hunt Looking To Put Five Wells In A 640-Acre Drilling Unit In The Charlson Oil Field -- February 25, 2017

Updates

February 26, 2017: I've always considered the Charlson oil field one of the better fields in the Bakken, but the field is not even on the top 20 list for a) overall production; or, b) production/well.

Original Post

 
Remember: regardless of the size of the drilling unit, or the length of the horizontal, operators are targeting wells with EURs of at least 500,000 bbls of oil these days.

This is pretty cool.

In a 640-acre laydown drilling unit, Petro-Hunt is looking to place five horizontal Bakken pool (middle Bakken or Three Forks) wells.

From the March, 2017, hearing dockets:

• Case #25671 (not a permit, but a hearing case number), Petro-Hunt, Charlson-Bakken, four wells on a laydown 640-acre unit; S/2 of sections 35/36-154-95; six wells on an overlapping 1280-acre unit; McKenzie County

This is the approximate 640-acre drilling unit, the south half of the two neighboring sections, south of the river:

Petro-Hunt is looking to have as many as five wells in that 640-acre drilling unit outlined in red. The producing well in that drilling unit (#16963) has produced over 700,000 bbls in less than ten years and is still going strong. It will be interesting to look at the production profile of this well when four more wells are "squeezed" into this small drilling unit. 

Note the dual lateral that was drilled back in 2008:

16963: note the two laterals going off in different directions; one lateral fracked with 580,578 lbs of sand; the other lateral fracked with 470,943 lbs of sand.

• 16963, 423, Petro-Hunt, USA 35D-1-1H, Charlson Three Forks, t12/08; cum 716K 12/16:
• The production profile for the first two years, pretty impressive:

BAKKEN	1-2011	31	10352	10845	772	14132	10420	3495
BAKKEN	12-2010	31	10641	10516	744	9057	8840	0
BAKKEN	11-2010	30	10029	9965	674	14832	6671	7951
BAKKEN	10-2010	31	10606	10984	712	15545	9194	6134
BAKKEN	9-2010	30	10632	10013	713	15373	11392	3771
BAKKEN	8-2010	31	11307	11438	803	15828	8614	6997
BAKKEN	7-2010	31	11730	11426	838	15648	6636	8795
BAKKEN	6-2010	30	11671	11738	857	15394	4423	10761
BAKKEN	5-2010	31	12527	12602	902	12635	877	11541
BAKKEN	4-2010	30	12645	12771	902	18157	877	17070
BAKKEN	3-2010	31	13689	13385	970	19090	8089	10784
BAKKEN	2-2010	28	12882	13097	933	17663	14103	3364
BAKKEN	1-2010	31	14937	14836	1051	20312	16959	3136
BAKKEN	12-2009	31	15787	15729	1155	21066	16011	4838
BAKKEN	11-2009	30	15937	15995	1237	22310	9288	12812
BAKKEN	10-2009	31	17588	17987	1629	24681	21484	2980
BAKKEN	9-2009	30	15668	15286	1214	20404	19496	698
BAKKEN	8-2009	31	12737	13015	822	17691	13015	4459
BAKKEN	7-2009	31	13836	13625	892	16476	11800	4459
BAKKEN	6-2009	30	14163	14537	1004	16482	4235	12037
BAKKEN	5-2009	31	15556	15605	1125	18343	21	18112
BAKKEN	4-2009	30	16430	15914	1287	19949	3906	15833
BAKKEN	3-2009	31	18371	18615	1641	17030	17030	0
BAKKEN	2-2009	26	12301	12349	1435	12188	12188	0
BAKKEN	1-2009	31	9912	9841	899	10219	10219	0

Look how long that well produced at a rate over 10,000 bbls/month with minimal amount of proppant. 

The well had a "slow" decline rate and still produces over 3,000 bbls of oil each month.

CLR's Wiley And Bailey Wells In Pershing Oil Field

Updates

July 9, 2022: production data below, updated.

March 14, 2020: update. 

November 25, 2018: graphic updated --

Original Post

By the way: this is CLR's second 10-well pad in two consecutive days. Supports my thesis that we're seeing the early days of Bakken 2.0. 

Ten-well Bailey/Wiley pad permitted October 25, 2016. In a straight line west-to-east, each well vertically separated only 45 feet from its neighbor. This is the proposed location for these ten new wells (five Bailey wells and five Wiley wells):

The ten-well pad in the graphic above: each well will be 1,265 feet from the north line, and they will extend from 2,076 feet from the west line to 1,516 feet from the west line. Each well will be 45 feet vertically from its neighbor. The ten wells, west to east, these are huge wells, posting 40K to 55K in first full month of production:

• 37192, F/A, CLR, Wiley 13-25HSL2, Pershing, t--; 75K 12/20; cum 233K 5/22;
  
• 33117, 1,962, CLR, Bailey 8-24H, Pershing, 66 stages; 16.1 million lbs, t6/18; cum 397K 12/20; offline 2/20; back on line 4/20;  see this note; see this note; cum 468K 5/22;
  
• 33116, 1,733, CLR, Bailey 9-24H2, Pershing, t6/18; cum 319K 12/20; offline 2/20; remains off line 4/20; cum 330K 5/22;
  
• 33115, 1,950, CLR, Bailey 10-24H, Pershing, t6/18; cum 250K 12/20; remains off line 11/19; back on line 1/20; wow, talk about a nice well; cum 344K 5/22;
  
• 33114, 1.495, CLR, Bailey 11-24H2, Pershing, t6/18; cum 305K 12/20;  remains off line 11/19; back on line 1/20; another nice well; cum 360K 5/22;
  
• 33113, A/IA/1,563, CLR, Bailey 12-24H, Pershing, t6/18; cum 117K 12/20; off line a lot; remains off line 11/19; back on line 1/20; it will be okay; cum 152K 5/22;
  
• 33112, 2,526, CLR, Wiley 8-25H, Pershing, t7/18; cum 307K 12/20; cum 327K 5/22;
• 33111, 1,881, CLR, Wiley 9-25H2, Pershing, t7/18; cum 258K 12/20; off line all of 10/18; back on line as of 12/18; cum 290K 5/22;
  
• 33110, 1,720, CLR, Wiley 10-25H, Pershing, t7/18; cum 323K 12/20; cum 366K 5/22;
• 33109, 1,923, CLR, Wiley 11-25H2, Pershing, t6/18; cum 276K 12/20; cum 307K 5/22;
• 33108, 1,547, CLR, Wiley 12-25H, Pershing, t7/18; cum 266K 12/20; cum 303K 5/22;
  

Other wells sited in that same section, 25-150-97:

• 17742, 668, CLR, Wiley 1-25H, t6/09; cum 206K 12/20; huge jump in production in 7/18 after neighboring wells fracked; cum 213K 5/22;
  

• 19935, 309, CLR, Wiley 2-25H, a Three Forks well, 30 stages, 2.8 million lbs, t12/11; cum 257K 12/20;  huge jump in production in 7/18 after neighboring wells fracked; cum 272K 5/22;
  
• 19933, 495, CLR, Bailey 2-24H, a Three Forks well, 24 stages, 2 million lbs, t1/12; cum 208K 12/20; huge jump in production in 7/18 after neighboring wells fracked; cum 214k 5/22;
  
• 19936, IA/724, CLR, Wiley 3-25H, 30 stages, 2.7 million lbs, t12/11; cum 200K 5/20; remains off line 5/22;
  
• 19934, 877, CLR, Bailey 3-24H, t12/11; cum 325K 12/20; huge jump in production in 5/18 after neighboring wells fracked; cum 349K 5/22;
  

• 28561, 759, CLR, Bailey 4-24H2, a Three Forks well, 40 stages, 8.2 million lbs, t9/15; cum 263K 12/20; huge jump in production in 5/18 after neighboring wells fracked; cum 281K 5/22;
  
• 28562, 1,474, CLR, Bailey 5-24H, 30 stages, 6.1 million lbs, t5/15; cum 280K 12/20; nice jump in production in 5/18 after neighboring wells fracked; cum 298K 5/22;
  
• 28563, 985, CLR, Bailey 6-24H1, a Three Forks well, 30 stages, 6.2 million lbs, t8/15; cum 208K 12/20; cum 226K 5/22;
• 28564, dry (casing would not hold; would be plugged, re-permitted), CLR, Bailey 7-24H, t10/14;
  
• 29808, 1,145, CLR, Bailey 7-24XH, t12/15; cum 325K 12/20; cum 354K 5/22;
  

• 28565, 1,212; CLR, Wiley 4-25H2, Pershing, t8/17; cum 242K 12/20; huge jump in production in 5/18 after neighboring wells fracked; cum 300K 5/22;
  
• 28566, 693, CLR, Wiley 5-25H, Pershing, t8/17; cum 306K 12/20; huge jump in production in 5/18 after neighboring wells fracked; cum 343K 5/22;
  
• 28567, PA/dry, CLR, Wiley 5-25H,t1/15; no production,
• 30578, 1,188, CLR, Wiley 6-25H1, Pershing, t8/17; cum 319K 12/20; offline 3/20; remains off line 4/20; back on line; cum 376K 5/22; jump in production / halo effect;
  
• 30577, n/d, CLR, Wiley 7-25H, Pershing, t8/17; cum 327K 12/20;  off line 3/20; remains off line 4/20; a most unusual production profile; back on line 10/20; cum 352K 5/22;
  

Just north of this section, see this post:

• 17770, 406, CLR, Bailey 1-24H, a Three Forks well, 22 stages, 1.7 million lbs, t4/10; cum 233K 12/20; stripper well, June 17, 2016; off line 2/20; remains off line 4/20; back on line; cum 251K 5/22;