A Request For Help From Readers -- Unitization -- December 8, 2020

Updates

December 9, 2020: sent to me by a reader last night shortly after the original note was posted --

I received my first royalty payment from XTO for the GBU on 06/25/19. XTO pays royalties on the 25th and 30th of each month, the check dated the 30th is usually for the GBU.

By the way, one can find the unit boundaries at the NDIC GIS map server, example:

Original Post

A few fields have been unitized in the Bakken. 

A reader asked a question about unitization. 

I don't have a dog in that fight; I don't have personal experience.  I did not have an answer. I am curious if any mineral owner has experience that could shed light on this -- more for the reader's benefit than mine.

We will use GBU as the example (because that was the specific unit the reader asked about).

GBU = Grinnell Bakken Unit.

See this post where GBU Janice was noted. 

Two permits renewed:

• EOG: a Clarks Creek permit in McKenzie County;
• XTO: a GBU Janice permit in Williams County;

For other XTO GBU wells, see this post. 

The reader asked "when would royalties start to reflect unitization of this field?"

I assume royalties would be affected effective the date the field was unitized. 

Going though a few of the "GBU" wells suggest this occurred on/about May, 2019. [Wow, was I on target or not -- see updates above. Wow!]

This, of course, raises many more questions but instead of running through a litany of questions and showing my ignorance, I will simply ask for any input from any mineral owner, land man, or armchair oil and gas lawyer that might shed light on this phenomenon.  

For those interested, one can google "oil field unitization." I did not spend a lot of time on this but this site (page 13 of the download / page 437 of the source -- both the same page) seems to provide a fair amount of useful information which suggested to me that the date the regulating authority granted unitization of a field is when mineral royalties would reflect that change. 

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For The Archives

I first spotted Miranda on late night British comedies on local PBS station. I was impressed.

Now this.

Random Update On CLR's Plan To Unitize Long Creek -- November 20, 2018

A reader wrote to tell me that he has received paperwork from CLR regarding Long Creek unitization. Needs mineral owner approval. In the December, 2018, hearing dockets:

CLR and the Long Creek development, 56 more wells in the unit. All owners received a load of papers from CLR. We will all get a new decimal interest when they start and share from all wells in the unitized area.

Long Creek is about eight miles east-southeast of Williston:

Photos from the reader:

Long Creek is tracked here, but it has not been updated in a very, very long time.

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The Literature Page

As noted, the Bible is one of the books I am now reading for history and literary reasons. I will limit myself to the Hebrew Bible, the Pentateuch, the Torah for now.

Back in 2012, I read a biography of the bible, by Karen Armstrong, Notes are here. I am now carrying that small book in my backpack and will re-read it and update the notes now that I have a better feeling for the authorship and the first five books of the Bible.

Karen's biography begins, Chapter 1, Torah --

In 597 BCE, the tiny state of Judah in the highlands of Canaan broke its vassalage treaty with Nebuchadnezzar, ruler of the powerful Babylonian empire. It was a catastrophic mistake. Three months later, the Babylonian army besieged Jerusalem, Judah's capital. The young king surrendered immediately and was deported to Babylonia, together with some ten thousand of the citizens who made the state viable: priests, military leaders, craftsmen, and metal workers. As they left Jerusalem, the exiles would have taken one last look at the temple built on Mount Zion by King Solomon (c. 970 - 930 BCE), the centre of their national and spiritual life, sadly aware that in all likelihood they would never see it again. Their fears were realized; in 586, after yet another rebellion in Judah, Nebuchadnezzar destroyed Jerusalem and burned Solomon's temple to the ground.

Key words:

• Judah: southern kingdom
• Canaan: land of milk and honey; the promise(d) land
• Babylonia: Babel
• Jerusalem: capital
• Mount Zion
• Solomon's Temple

A most interesting book, The Book of J, translation by David Rosenberg, commentary by Harold Bloom, fills in much of the void. It is conjecture and opinion, of course, but it allows the reader to reflect and consider his/her own ideas about that period of time and how the Bible came to be. Notes of that book are here. 

This is the New York Times review of The Book of J, translation by Rosenberg: link here.

Hope Springs Eternal -- XTO Proposes Unitizing A Large Area Of The Bakken -- September 28, 2018

Grinnel-Bakken and Hofflund-Bakken are contiguous -- is that the right word? -- think of a long rectangular field, with the eastern fourth being the Hofflund, and the western three-quarters being the Grinnell. I don't know much about the Hofflund -- I see it once in awhile -- but the Grinnell is a great field. It's amazing how much of the best Bakken is below the river and the lake. God has a sense of humor. The Native Americans were right: "we" never should have flooded what is now Lake Sakakawea. 

Hofflund:

Grinnell:

Link here. Data points:

• XTO would like to unitize the Hofflund-Bakken and the Grinnell-Bakken oil fields as one large unitized unit
• Petrogulf Corp is one of the 150 working interest owners
• Petrogulf objected to unitizing the two fields as one unitized unit
• Petrogulf felt unitizing the two units as one unit would be "unfair" because geology is "so different"
• NDIC proposed separating the two units; but allow unitizing both -- separately
• NDIC also recommended changes to the royalty distribution formula that he said would make the plan more equitable (details not provided in the article)
• NDIC unanimous: the proposal goes forward but as two separate unitized fields: the Hofflund-Bakken unitized field; and the Grinnell-Bakken unitized field
• the proposal must now be approved by 55% of mineral owners

Flashback

• QEP tried unitizing the Helis Grail field years ago; the proposal was defeated 
• Helis Grail field is not unitized
• something tells me....

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Electric Switches 101

Unfortunately this was filmed in low light. But I had to take advantage of the moment. Sophia did not want this filmed but she agreed to one "take." Earlier, not filmed, was much better, but this will give you an idea of what we are working on.

Unitization -- What It Means For Mineral Owners

Earlier it was posted that QEP is looking to "unitize" the Grail-Bakken field in the Williston Basin, North Dakota.

I was hoping someone would ask the question: what does this mean for mineral owners? And someone has asked the question. I am not a mineral owner, so I prefer to let others answer.

You can join in the discussion over at the discussion group (open to all, no registration required, but all comments are moderated, meaning there could be a delay before comments are posted, among other things).

Websites:

• legal definition/discussion

Not knowing a thing about unitization other than the little bit from other websites, two things come to mind:

• the rules for the entire field would now be uniform, making permitting process more streamlined
• unitization would allow operators to be more effective/efficient in developing the field (maximizing production from each mineral acre)

Assuming that every last acre in the Grail is now held by production, I can't imagine unitization would adversely affect mineral rights owners all that much, but I don't know. Hopefully folks will provide some insight.

I have blogged about unitization in the past; some of these posts are very old, and I'm almost embarrassed to bring them to your attention again. I am learning as I go along, and some of these posts are, well, quite embarrassing:

• FAQ #35
• unitization and EOR
• unitization of Lost Bridge-Bakken; another post on unitization of Lost Bridge-Bakken
• unitization, waterflooding in Canada
• unitization and EOR, in passing
• unitization of Corral Creek-Bakken by BR

Oakdale Oil Field Update

Locator: 10010OAKDALE.

 

January 15, 2026: permits updated. Production update in only a few cases. Wells of interest at this post.

January 29, 2025: production data updated.

 

Permits in Oakdale Oil Field

 

2026
 

 

2025
None
 

 

2024

None.

 

 

2023
None 

 

2022

None. 

 

2021 

• 38613, drl/A, CLR, Whitman FIU 4-34H1, Oakdale, t7/22; cum 510K 11/25;
• 38533, AL/A, CLR, Whitman FIU 13-34HSL1, Oakdale, t7/22; cum 240K 11/25;
• 38532, AL/A, CLR, Whitman FIU 12-34H2, Oakdale, t7/22; cum 408K 11/25;
• 38500, drl/A, CLR, Whitman FIU 6-34H2, Oakdale, t8/22; cum 555K 11/25;
• 38499, drl/A, CLR, Whitman FIU 5-34H, Oakdale, t8/22; cum 607K 11/25;
• 38497, drl/A, CLR, Whitman FIU 10-34H, Oakdale, t7/22; cum 341K 11/25;
• 38496, drl/A, CLR, Whitman FIU 9-34H2, Oakdale, t9/22; cum 367K 11/25;
• 38495, drl/A, CLR, Whitman FIU 8-34H, Oakdale, t9/22; cum 517K 11/25;
• 38494, drl/A, CLR, Whitman FIU 7-34H1, Oakdale, t9/22; cum 584K 11/25;

2020

• 37794, drl/NC-->drl/A, CLR, Carson Peak 13-35H, first production, 5/21; t--; cum 85K 7/21; cum 268K 4/22; cum 442K 11/24; cum 483K 11/25; 
  
• 37716, drl/NC-->drl/A, CLR, Carson Peak 12-35H1, first production, 5/21; t--; cum 86K 7/21; cum 252K 4/22; cum 430K 11/24; cum 457K 11/25;
• 37715, drl/NC-->drl/A, CLR, Carson Peak 11-35H2, first production, 5/21; t--; cum 112K 7/21; cum 313K 4/22; cum 547K 11/24; cum 574K 11/25;
• 37714, drl/NC-->drl/A, CLR, Morris 13-26H, first production, 5/21; t--; cum 72K 7/21; cum 248K 4/22; cum 357K 11/24;
  
• 37713, drl/NC-->drl/A, CLR, Morris 12-26H1, first production, 5/21; t--; cum 57K 7/21; cum 197K 4/22; cum 300K 11/24;
  

2019

• None.

2018

• 35273, F/2,405, Carson Peak 4-35H2L, t6/19; cum 562K 3/21; cum 616K 7/21; cum 693K 3/22; offline 4/22; cum 760K 11/24;
  
• 35272, 3,376, Carson Peak 4-35HSL, t6/19; cum 677K 3/21; almost 700K in less than two years; cum 720K 7/21; cum 791K 2/22; offline 3/22; cum 926K 11/24;
  
• 35109, F/956, Morris 7-26H2, t4/19; cum 304K 1/21; off line 1/21; back on line 5/21; cum 311K 7/21; cum 362K 3/22; off line 4/22; cum 425K 11/24;
  
• 35108, 1,824, Carson Peak 6-35H1, t5/19; cum 448K 3/21; off line for much of 2/21 - 3/21; cum 481K 7/21; cum 530K 3/22; offline 4/22; cum 727K 11/24;
  
• 35087, drl/A, Morris 11-26H, Oakdale, first production, 5/21; t--; cum 108K 7/21; cum 254K 4/22;
  
• 35086, drl/A, Morris 10-26H2, first production, 5/21; t--; cum 85K 7/21; cum 200K 4/22; cum 209K 4/22; cum 264K 11/24;
  
• 35085, drl/A, Morris 9-26H, Oakdale, first production, 5/21; t--; cum 75K 7/21; cum 209K 4/22; cum 302K 11/24;
  
• 35084, drl/A, Carson Peak 1-35H1, first production, 5/21; t--; cum 101K 7/21; cum 308K 4/22; cum 531K 11/24;
  
• 35083, drl/A, Carson Peak 9-35H, first production, 5/21; t--; cum 81K 7/21; cum 262K 4/22; cum 538K 11/24;
  
• 35082, F/1,593, Morris 8-26H1, four sections; t4/19; cum 330K 9/20; off line 10/20; back on line 6/21; cum 341K 7/21; cum 408K 4/22; cum 451K 11/24;
  
• 35081, 3,556, Carson Peak 8-35H2, t5/19; cum 633K 1/21; off line 2/21; back on line 5/21; cum 648K 7/21; cum 666K 4/22; offline 4/22; cum 876K 11/24;
  
• 35080, 2,076, Carson Peak 7-35H, t6/19; cum 455K 12/20; off line 1/21; remains off line 7/21; back on line 8/21; cum 568K 4/22; cum 818K 11/24;
  

2017

• 34354, 2,485, CLR, Hawkinson 16-22HSL1, 4 sections, NENE 22-147-96; 465 FNL 681 FEL, see graphic; t2/19; cum 382K 3/21; cum 406K 7/21; cum 431K 4/22; off line 4/22; cum 488K 11/24;
  
• 34353, 2,913, CLR, Morris 4-23HSL, NENE 22-147-96; 466 FNL 636 FEL, see graphic; t3/19; cum 349K 3/21; cum 354K 7/21; cum 377K 4/22; off line 4/22; cum 411K 11/24;
  
• 34352, 2,698, CLR, Morris 523H2, NENE 22-147-96; 466 FNL 500 FEL, see graphic; t4/19; cum 277K 3/21; but essentially off line since 6/19; remains off line 9/19; back on line 10/19; cum 286K 7/21; cum 306K 4/22; off line 4/22; cum 338K 11/24;
  
• 34351, 1,969, CLR, Morris 6-23H, NENE 22-147-96; 467 FNL 456 FEL, see graphic; t4/19; cum 337K 3/21; off line most of 2/21 - 3/21; back on line 6/21; cum 348K 7/21; cum 390K 4/22; offline 4/22; cum 439K 11/24;
  

2016

• None.

2015 (list is compete)

• 31104, 133, CLR, Hawkinson 15-22H, Oakdale, t4/16; cum 100K 3/21; off line since 11/18; see below; back on line 1/19; cum 107K 4/22; cum 132K 11/24;
  

2014

• No new Oakdale permits in 2014.

2013

• No new Oakdale permits in 2013.

2012

• Only the CLR Hawkinson wells noted below

2011

• None

Hawkinson Wells

Hawkinson wells in section 22/27-147-96 in Oakdale oil field (it should be noted that wells #20208 and #20211 are in this spacing unit, but sited in section 34 to the south):

• 18275, single well, 1,020, CLR, Hawkinson 1-22H, t2/10; cased hole, 2 million lbs; cum 733K 3/21; went off line 3/19; still off line 4/19; back on line as of 5/19; unremarkable change in production; cum 767K 11/24;
  

A singleton (see above):

• 31104, 133, CLR, Hawkinson 15-22H, t4/16; cum 95K 1/20; off line as of 11/18; back on line as of 1/19; still a lousy well; cum 132K 11/24;

There are two more Hawkinson wells that were drilled from the other end of the spacing unit:

• 20208, 960, CLR, Hawkinson 2-27H, Oakdale, 4-section spacing, Three Forks; 24 stages, 2.4 million lbs; t9/11; cum 472K 1/20; off line as of 5/18; back on line as of 2/19; cum 526K 11/24;
• 20211, A/AB-->A/263, CLR, Hawkinson 3-27H, Oakdale, 4-section spacing, middle Bakken, 24 stages, 2.4 million lbs, t9/11; cum 389K 1/20; was AB, now active again, back on line as of 2/18; not much production since coming back on line; off line 10/19 but then back online 1/10; cum 403K 11/24;
  

Three-well pad:

• 24223, 400, CLR, Hawkinson 4-22H2, Oakdale, Three Forks, 30 stages, 2.8 million lbs; t91/13; cum 382K 1/20; went offline 3/19; see this post; cum 498K 11/24;
  
• 24224, 681, CLR, Hawkinson 5-22H, Oakdale, middle Bakken, 30 stages, 2.8 million lbs, t9/13; cum 495K 1/20; went offline 3/19; see this post; cum 583K 11/24;
  
• 24225, 809, CLR, Hawkinson 6-22H3, Oakdale, Three Forks, 30 stages, 2.8 million lbs, t10/13; cum 236K 1/20; went off line 3/19; see this post; intermittent production until 5/19; cum 263K 11/24;
  

Five-well pad:

• 24282, 175, CLR, Hawkinson 7-22H2, Oakdale, middle Bakken, 29 stages, 2.7 million lbs, t10/13; cum 257K 1/20; off line since 11/18; back online as of 3/19; cum 282K 11/24;
  
• 24283, 504, CLR, Hawkinson 8-22H, Oakdale, middle Bakken, 29 stages, 2.7 million lbs, t11/13; cum 257K 1/20; cum 291K 11/24;
• 24284, AB/203, CLR, Hawkinson 9-22H3, Oakdale, Three Forks, 30 stages, 2.8 million lbs, t10/13; cum 151K 1/20; off line since 11/18; back online as of 1/19 but still a lousy well;cum 151K 8/20;
  
• 24285, 922, CLR, Hawkinson 10-22H1, Oakdale, Three Forks, 30 stages, 2.8 million lbs, t10/13; cum 193K 1/20; off line since 11/18; online as of 1/19; but still a lousy well; cum 219K 11/24;
  
• 24286, 323, CLR, Hawkinson 11-22H2, Oakdale, Three Forks, 30 stages, 2.7 million lbs, t10/13; cum 261K 1/20; off line since 11/18; back on line as of 1/19; looks like some increase in production; cum 308K 1124;
  

Three-well pad:

• 24350, 445, CLR, Hawkinson 12-22H3, Oakdale, Three Forks, t9/13; cum 204K 1/20; off line since 12/18; back on line for 6 days, 9/19; small amount of production; cum 270K 11/24;
  
• 24455, 2,323, CLR, Hawkinson 13-22H, Oakdale, middle Bakken, 29 stages, 2.7 million lbs, t10/13; cum 299K 1/20; off line since 10/18; on line for 15 days 3/19 but offline again as of 4/19; back on line as of 6/19; cum 375K 11/24;
  
• 24456, 542, CLR, Hawkinson 14-22H2, Oakdale, Three Forks, t9/13; cum 243K 1/20; off line since 10/18; back on line for 12 days in 3/19 but back off line as of 4/19; mediocre well at best; back on line as of 9/13; cum 254K 11/24;
  

Updates

May 27, 2021: Oakdale wells permitted in 2018, updated this date.

June 6, 2019: #24282 back on line after being offline for about five months; not much change in production; 

• 24282, 175, CLR, Hawkinson 7-22H2, Oakdale, t10/13; cum 282K 11/24;

February 4, 2019: lots of activity right now in this area. Several great wells off-line since 10/18; in addition, two new wells on DRL status are now on the 18858-18861 pad:

• 35272, 3,376, CLR, Carson Peak 4-35HSL, t6/19; cum 926K 11/24;
• 35273, 2,405, CLR, Carson Peak 5-35H2, t6/19; cum 760K 11/24;
  

June 4, 2014: Oakdale field is very small; only eight (8) sections. It is two sections wide (west/east) by four sections long (north/south). It has four 1280-acre spacing units; and CLR proposes two overlapping 2560-acre units in the June NDIC dockets.

Case (not permit) 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

Since 32 wells works out to 16 wells sited in every 1280 acres, that would suggest a maximum of 32 wells in every 1280 acres. I assume they wouldn't drill a well unless they anticipated a EUR of at least 500,000 bbls. 16 x 500,000 = 8,000,000 boe in each section. 8 million boe / 640 acres = 12,500 boe/acre. 

November 6, 2013: Hawkinson Unit density test produces at an initial combined rate of 14,850 boe per day from middle Bakken and Three Forks benches one, two and three. CLR will dedicate four rigs to drill mega-pads. CLR will drill 350 wells on 25 pads over the next four to five years.


October 18, 2012:  Three new CLR permits in Oakdale -- testing the lower benches of the Three Forks?

Original Post

I recently updated the Morris 2-26H well which is in the Oakdale oil field in the Williston Basin.

• 18860, 517, CLR, Morris 2-26H, Oakdale, Bakken; t5/11; cum 285K 10/17;  4-section spacing; cum 329K 11/24;
  

Here's the rest of the story:

• 18858, 715, CLR, Morris 3-26H, Oakdale, Bakken, t5/11; cum 478K 12/18;  (Kind of HUGE), 4-section spacing; off line as of 9/18; cum 522K 11/24;
  
• 18859, 680, CLR, Carson Peak 3-35H, Oakdale, Bakken, t5/11; cum 671K 12/18;  4 (Really HUGE); 4-section spacing; off line as of 10/18; cum 924K 11/24;
  
• 18861, 759, CLR, Carson Peak 2-35H, Oakdale, Bakken; t5/11; cum 718K 12/18;  (Really HUGE); 4-section spacing: off line as of 10/18; cum 752K 11/24;
  

This Eco-Pad is in the Oakdale oil field, a field we don't hear much about. That's because it is a very small field, all of eight (8) sections. In fact, it's hard to get more than a couple of Eco-Pads in a field this small. Smile.

The field is in the core Bakken, in the northwest corner of Dunn County and surrounded by some "name" oil fields, including Little Knife and Jim Creek. The field is "owned" by Continental Resources.

Just east of this Eco-Pad is another Continental Resources Eco-Pad, the Hawkinson-Whitman Eco-Pad, 4-section spacing:

• 20208, A/IA/960, CRL, Hawkinson 2-27H, Oakdale, Bakken; t9/11; cum 452K 12/18; off line as of 6/18; cum 526K 11/24;
• ******20210, 803, CLR, Whitman 2-34H, Oakdale, Bakken, t9/11; cum 1.629573 million bbls/112/18; FracFocus/NDIC: no record of refrack; huge jump 9/18; cum 1.828001 million bbls 1124;
  
• 20211, AB/263, CLR, Hawkinson 3-27H, Oakdale, Bakken; t9/11; cum 385K 10/17; cum 403K 11/24;
  
• **** 20212, 482, CLR, Whitman 3-34H, Oakdale, Bakken; t9/11; 308K 12/18; re-fracked 9/17; cum 1.154427 million bbls 11/24;

Just to the west of the Hawkinson-Whitman Eco-Pad is a superb CLR well:

• 17061, IA/664, CLR, Whitman 11-34H, Oakdale, Bakken; tested 6/08; 461K 12/18;

To the north is an old legacy well, still considered active, but last produced in 2008:

• 6130, 220/PA, RM Resources, Hawkinson 1-27, Oakdale, Madison; t8/77; cum 341K as of 1/12 but no production since 5/08, abandoned

Another nice horizontal well drilled in this boom in this oil field:

• 18275, 1,020, CLR, Hawkinson 1-22H, Oakdale, Bakken; t2/10; cum 712K 12/18; time to re-frack; cum 767K 11/24;
  

Others:

• 17079, 559, CLR, Carson Peak 44-2H, Oakdale, Bakken; t6/08; cum 311K 12/18; off line as of 11/18;cum 384K 11/24;
  
• 17334, 811, CLR, Morris 1-23H, Oakdale, Bakken, t11/08; cum 278K 12/18; off line as of 8/18; cum 395K 11/24;
  

Everything suggests this will end up being a very good field. Eight sections, two Eco-Pads: one wonders if this field is an early candidate for unitization.

Unitization and How Many Wells In One Section / One Spacing Unit in the Bakken? -- North Dakota, USA

A lot of folks have asked me over the past two years, how many wells can "they" put in a spacing unit, or how many wells can "they" put in a section in the Bakken? How about 14 wells in one 2560-acre spacing unit (essentially one well every 180 acres).

In the August, 2011, NDIC hearing dockets, here is one example: 

Case 15373, BR: Dimmick Lake-Bakken; Johnson Corner-Bakken; 12 additional hz wells on a single 2560-spacing unit and increase the stratigraphic definition of the Bakken Pool, McKenzie (this amounts to a well every 180 acres, if you include the two that are already there)

This is case # 15373. Burlington Resources will request that it be allowed to place as many as 12 "additional" wells on a single 2560-acre spacing unit. The 2560-acre spacing unit will be composed of two 1280-acre spacing units that already exist: one in Dimmick oil field, and one in Johnson Corner oil field. Specifically sections 28 and 33 in T151N-R96W; and, sections 4 and 9 in T150N-R96W.

These four sections are contiguous and run north-south.

There are already two producing wells in this (if approved) 2560-acre unit:

• 17680, 463, BR, Denali 31-28H, spudded 10/17/08; Dimmick Lake; 83,000 bbls to date
• 18225, 625, BR, Norman 1-9H, spudded 11/16/09; Johnson Corner; 85,000 bbls to date

Neither of these wells is all that spectacular. The IPs were nice, but not spectacular, and neither well has yet reached 100,000 bbls cumulative production yet.  As of June, 2011, the most recent reporting period, neither well is yet on a pump; both are flowing on their own. Both were taken off-line in May and June, suggesting a work-over, a pump, or something else.

The fields are good fields but they are not in the best Bakken (like the Sanish).

I don't know how unitization plays out but I've been told that before unitizing a field, and preparing the field for secondary and then tertiary enhanced oil recovery (water flooding; CO2 injection), one needs to maximize the number of wells going into the field.

I've talked about this before. It appears that fracturing is effective only to about 500 feet (radius) / 1,000 feet (diameter) with the well bore at the center. A section is a mile square, so to effectively fracture the entire section, one could place three to five horizontal wells. With two wells already there and requesting as many as 12 "additional" wells, one would have as many as 14 wells in this one 2560-acre spacing unit.

Note, that in the August hearings, BR is requesting to unitize the Lost Bridge-Bakken field, even though the producing wells in that field are predominantly CLR's. The Johnson Corner well above (#18225) was originally a CLR well, but is now operated by BR. There is obviously a close working relationship between CLR and BR as we move closer to unitization in the Bakken.

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

Case 15379 is even more peculiar:

15379, QEP: Heart Butte-Bakken, create one 2560-acre unit; 12 hz wells; Dunn, McLean Counties. The 2560-acre spacing unit will be composed of two 1280-acre spacing units that already exist: both are in Heart Butte oil field and all four are under the river, or very near the river. Specifically sections 10, 11, 14, and 15 (forming a square) in T149N-R91W.

This is what is peculiar: according to the GIS map server, there are NO wells in any of these sections. Not even any permits yet. So, 12 wells in an area that has no wells yet. Very strange, indeed.

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

Case 15375 is similar, but there are two wells already there producing:

15375, BR: Pershing-Bakken; North Fork-Bakken; 12 additional hz wells on a single 2560-acre unit; amend the stratigraphic definition of the Bakken pool, McKenzie. The 2560-acre spacing unit will be composed of two 1280-acre spacing units that already exist: one unit is in Pershing oil field; one is in North Fork oil field. The units are sections 4, 9, 16, and 21 in T149N-R96W; these four sections are contiguous, running north-south.

There are already two producing wells in this (if approved) 2560-acre unit:

• 17432, 156, BR, Curtis 1-4H, spudded 12/7/08; Pershing oil field; 84,000 bbls to date
• 17340, 805, BR, Saddle Butte 11-16H, spudded 2/25/09; North Folk; 43,000 bbls to date

Neither has a pump; both continue to flow.  Again, these are nice fields, but nothing spectacular.

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

So, I certainly don't understand it. This is what I see:

• BR has a request into unitize a Bakken field, Lost Bridge
• These 2560-acre units are all BR units
• I've been told that before one unitizes a field, one maximizes number of wells in the field
• The producing wells on both 2560-acre units with producing wells are still flowing on their own; no pumps (four wells altogether; all flowing; spudded a couple of years ago)
• The wells are  not that spectacular based on IPs or cumulatives to date, but they continue to flare despite being spudded years ago (albeit only a small amount; most natural gas is collected/sold)

Here We Go -- Unitization in the Bakken, North Dakota, USA -- BR Wants to Unitize Lost Bridge Oil Field; XTO "Owns" The Field?

Updates

July 12, 2011: I am being told that possibly BR is doing contract work for XTO (XOM) due to BR's experience elsewhere in North Dakota with unitization. BR was involved with unitization in Cedar Hills oil field south of Marmarth, North Dakota; the other operator was CLR.

Original Post

Link here.

BR has an application into the NDIC to unitize the Lost Bridge oil field. It is interesting that BR has the application because it was my feeling that XTO (XOM) pretty much owned the field. This was based on the permits and wells already in the Lost Bridge oil field, not any review or knowledge of actual net acreage controlled by any operator in the field.

It is interesting: according to the NDIC, BR has no permits filed in Lost Bridge oil field.

NDIC Dockets -- Unitization in Lost Bridge -- Bakken, North Dakota, USA

Note: the NDIC generally holds hearings during the third week of the month. These three cases are being held very early. I don't know if this means something new, if NDIC is taking a well-deserved vacation later in the month of August, or if we will see additional cases later. 

Thursday, August 4, 2011

15332: BR, unitization in Lost Bridge-Bakken, Dunn County
15333: BR, unitization in Lost Bridge-Bakken, Dunn County

Thursday, August 4, 2011, Supplement

15334: Lantech, saltwater disposal

Thursday, August 25, 2011

15332, cont'd: BR, unitization in Lost Bridge-Bakken, Dunn County
15333, cont'd: BR, unitization in Lost Bridge-Bakken, Dunn County

Unitization: Great Explanation -- Bakken, North Dakota, USA

For a great description of "unitization," click here and go to "second comment," posted June 30, 2011. [This link is now broken.]

I've also linked it at my "frequently asked questions" page: this appears to be best the answer from most reliable source (this site is down) posted July 1, 2011:

"Basically, under untization, the spacing units disappear and the entire  field boundary lines become a big spacing unit, where all the owners within the field share in production from the entire field, which is allocated to  the owners by an agreed upon formula. The field becomes one big "spacing  unit," because the oil is being artificially forced across would have been the old spacing unit boundaries by the secondary recovery methods  (i.e., waterflood, CO2 etc.).  There will be a hearing or a number of  hearings with the DMR.

The state law requires that 60% of the mineral ownership approve of the  unit, and I believe votes are weighted by amount of acreage owned in the  unit. Most of the larger, older, conventional (i.e., non-Bakken) fields have  been unitized in ND -- Beaver Lodge, Blue Buttes, Fryburg, Big Stick.  The only one I'm aware that was defeated by the mineral owners was in Little  Knife field (Madison pool), and I think most would agree that such action  left a lot of recoverable oil in the ground.

Don't hold me to this, but if you are leased -- and your leases are not currently held by production -- if your leases are included in the unit (and  assuming the unitization plan is approved), they will be considered to be under production, as you will receive royalties pursuant to the formula."

An earlier source said this, which I posted August 2, 2010: Whatever unitization is, it remains a "non-issue" in North Dakota as of 2010. Seriously, here the discussion begins  (this site is down). Unitization is similar to pooling, but it occurs when producer(s) are ready to use enhanced oil recovery to maximize production from a common reservoir. With the Bakken being one huge continuous "reservoir" it's  hard to see how unitization could work, unless they do it by field, an arbitrary designation, in my mind, when it comes to the Bakken. Sixty percent of royalty owners (weighted) must agree to unitization before the NDIC will authorize it. To date, unitization has not occurred in North Dakota (August 2, 2010).

The NDIC hearing docket for August, 2011, will consider unitization of Lost Bridge-Bakken. The state is considering unitizing the Little Missouri State Park, October, 26, 2011.

An effort to unitize the Grail oil field failed. The operator took the case off the NDIC hearing dockets when faced with a fair amount of opposition to unitization.