Random Look At An MRO TAT USA Well In Antelope Oil Field -- February 3, 2018

Updates

March 20, 2018: production data updated; this turned out to be quite a re-frack.

Original Post

The graphic:

See this post.

MRO horizontals along #19144 are in the process of being fracked (some have reported production data after being fracked). I was curious what production data for #19144 looks like. Here is the well and recent production:

• 19144, 952, MRO, TAT USA 34-22H, Antelope oil field, Sanish pool; t3/11; cum 346K 12/17;

Recent production data:

Pool	Date	Days	BBLS Oil	Runs	BBLS Water	MCF Prod	MCF Sold	Vent/Flare
SANISH	12-2017	8	8163	8540	0	10702	698	9119
SANISH	11-2017	2	1407	931	0	1111	0	948
SANISH	10-2017	0	0	0	0	0	0	0
SANISH	9-2017	0	0	0	0	0	0	0
SANISH	8-2017	0	0	0	0	0	0	0
SANISH	7-2017	3	120	225	51	194	8	136
SANISH	6-2017	30	2411	2485	536	2778	0	1941
SANISH	5-2017	31	2487	2510	520	2887	15	2014
SANISH	4-2017	30	2578	2565	487	2863	21	1987
SANISH	3-2017	27	2248	2259	452	2508	2	1772
SANISH	2-2017	28	2463	2460	474	2760	33	1941
SANISH	1-2017	31	2449	2512	487	2773	75	1850
SANISH	12-2016	31	2506	2465	462	3167	24	2436
SANISH	11-2016	30	2439	2402	455	3075	0	2384

After coming back on line, this well produced 8,000 bbls of crude oil over eight days which extrapolates to about 30,000 bbls/month. It turns out #19144 was re-fracked. According to FracFocus this well was re-fracked 11/3-5/17: 1.76 million gallons of water, and 9% sand.

Flashback! What's All This Talk About Running Out Of Drilling Locations In The Bakken? -- February 3, 2018 -- Update On Oasis Case #25524 -- 90 Wells In Small Area In Northeast McKenzie County

Oasis with plans for 90 wells in one small geographic area in the Bakken.

From a post just one year ago:

NDIC hearing dockets, case #25524, from the January, 2017, hearing dockets.

• Field: Dimmick Lake, Siverston, and/or Johnson Corner-Bakken
• County: McKenzie
• Oasis, i) 3 wells on each of six overlapping 2560-acre units (see graphic): A, B, C, D, E, F; note that (A) has been withdrawn (a request for 3 wells on an overlapping 2560-acre unit)
• Oasis, ii) 18 wells on each of four 1280-acre units (see graphic (G, H, I, J)

The graphic (the text is placed in the center of the drilling units):

• A (withdrawn), B, C, D, E, F: overlapping 2560-acre units (4 sections, all units are 2x2)
• G, H, I, J:  1280-acre units (all stand-up units)

Update On Oasis Case #25524 -- 90 Wells In Small Area In Northeast McKenzie County -- March 31, 2017

NDIC hearing dockets, case #25524, from the January, 2017, hearing dockets.

• Field: Dimmick Lake, Siverston, and/or Johnson Corner-Bakken
• County: McKenzie
• Oasis, i) 3 wells on each of six overlapping 2560-acre units (see graphic): A, B, C, D, E, F; note that (A) has been withdrawn (a request for 3 wells on an overlapping 2560-acre unit)
• Oasis, ii) 18 wells on each of four 1280-acre units (see graphic (G, H, I, J)

The graphic (the text is placed in the center of the drilling units):

• A (withdrawn), B, C, D, E, F: overlapping 2560-acre units (4 sections, all units are 2x2)
• G, H, I, J:  1280-acre units (all stand-up units)

Slawson Proposes Another 18 Wells In A Drilling Unit With Seven Long Laterals -- March 30, 2017

Link here.

The hearing dockets are tracked here.

From the April, 2017, NDIC hearing dockets:

• 25792, Slawson, Elm Tree-Bakken, 18 wells on a 1280-acre unit; McKenzie; 30/31-153-93

The graphic:

Slawson To Drill As Many As 30 Wells On One 640-Acre Drilling Unit -- March 30, 2017

Updates

November 13, 2019: new graphic --

Original Post

Disclaimer: this was done very, very quickly. There will be factual and typographical errors. I have not had a chance to proofread this. I may not get back to this until later this evening. Don't quote me on any of this for now. 

Remember: each well stands on its own. Generally speaking, operators will not drill a Bakken well (middle Bakken, four benches of the Three Forks) without expecting a EUR of at least 750,000 bbls. 

Back-of-the-envelope: 24 x 750K = 18,000K = 18 million bbls from one section x $40/bbl = $720 million at the wellhead. There are already 6 wells projected for this section, thus another 4.5 million bbls. 

In fact, in this area, one should expect EURs of 1.5 million bbls/well. Maybe not all the wells at all the target formations, but certainly for the "better" formations (at least two, maybe three, of the five).

Back on  April 5, 2013, this was posted:

If one moves the needle to 6%, 600,000-bbl EURs, and four wells per section, one gets in the neighborhood of 40 million bbls/section/OOIP in the Bakken on the North Dakota side of the border. 

But don't take my word for it. This is from Legacy Oil talking about the Spearfish:

"In terms of resource potential, the regional extent of the Spearfish is still being delineated, however, in areas already shown to be prospective, reservoir parameters can suggest potential OOIP to be in the realm of 9.0 to 15.0 million barrels per section, which could represent 2-3 times what the southeastern Saskatchewan Bakken offers on average."

That's the Spearfish, and the Bakken is known to be a whole lot better.

My hunch is, based on what some operators said some years ago, some operators are getting more than 6% of the OOIP on primary production.

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

From the April, 2017, NDIC hearing dockets (link here):

• 25789, Slawson, Clarks Creek-Bakken, 24 wells on an existing 640-acre unit, section 12-151-95, McKenzie County

The graphics:

A) overview of 640-acre units in the area of this drilling unit:

B) The 640-acre drilling unit:

C) Closer view of the multi-well pads in the immediate area:

Random Update Of An Area Of Interest In Charbonneau Oil Field -- March 30, 2017

It was noted on January 27, 2017, that Emerald Oil, Inc., had transferred 130 wells to Petro-Hunt, LLC.

Slawson's Torpedo Federal Wells -- March 24, 2017

The Wells

Twelve producing wells (DUCs) reported as completed:

• 31278, 4,862, Slawson, Torpedo Federal 10H, t12/18; cum 178K after 41 days; cum 574K 2/20; off line 2/20; see this post;
• 31277, 825, Slawson, Torpedo Federal 9H, t12/18; cum 238K 4/20; off line 3/20;
• 31276, 2,942, Slawson, Torpedo Federal 8H, t12/18; cum 323K 4/20; off line 3/20;
  
• 31275, 3,632, Slawson, Torpedo Federal 7H, t12/18; cum 304K 3/20; off line 3/20;
• 31274, 3,205, Slawson, Torpedo Federal 6H, t12/18; cum 24K after 19 days; cum 271K 3/20; off line 3/20;
• 31273, 2,254, Slawson, Torpedo Federal 5H, t12/18; cum 34K after 39 days; cum 218K 3/20; off line 4/20;
• 31272, 1,090, Slawson, Torpedo Federal 4H, t12/18; cum 35K after 37 days; cum 233K 4/20; off line 4/20;
• 31271, 1,109, Slawson, Torpedo Federal 3H, 33-061-03689, Big Bend, 10.8 million gallons of waer; 89% water, t12/18; cum 13K after 16 days; cum 208K 3/20; off line 3/20;
• 31270, 1,523, Slawson, Torpedo Federal 2H, 33-061-03688, Big Bend, no production data, fracked 9/7/2018 - 9/15/2018; 6.9 million gallons of water; 89% water; t12/18; cum 19K after 29days; cum 173K 3/20; off line 3/20;
• 31269, 1,857, Slawson, Torpedo Federal 1H, 33-061-03687, Big Bend, no production data, fracked 9/5/2018 - 9/12/2018; 5.9 million gallons; 89% water; t12/18; cum 18K after 27 days; cum 187K 3/20; off line 4/20;
• 31289, 1,794, Slawson, Bandit Federal 1 SLH, t12/18; cum 29K after 34 days; cum 271K 4/20; off line 4/20;
• 31279, 3,794, Slawson, Rebel Federal 1SLH, t12/18; cum 49K after 45 days; cum 426K 3/20; off line 3/20;
• 18924, 1,361, runs south, parallels #31289 which runs north; was off-line for a month, 9/18; back on line 10/18; t2/11; cum 551K 4/20; off line 4/20; subtle, perhaps, increase in production when it came back on line;
  

Updates

June 10, 2020: most of the Torpedo Federal wells are off line, probably due to low oil prices.  Updated graphic:

October 28, 2018: update. It appears that all eleven wells have now been drilled to depth; ten of the eleven wells are on SI/NC status; the eleventh is on drl status. Note: there are twelve wells on this pad, but #31289 runs north; whereas the other eleven run south under the river/lake.

November 15, 2017;  I can't imagine anyone being interested, but this is the link to the environmental impact study Slawson provided during the permitting process. It will open as a PDF, probably on your desktop.

April 1, 2017: The Bismarck Tribune has a story on this multi-well pad. 

March 25, 2017: this is pretty amazing if "we're" talking about the same wells. But that would not make sense. Yesterday I just happened to come across these Slawson permits/wells. I was just scanning the map and somehow happened upon these wells. Nothing more to the story. Then a few minutes ago, I was reading the Williston Wire. I had received it some days ago but didn't get to it until now. And there it was: an article on the BLM approving a permit for Slawson to drill the first eight of 11 wells from a single pad. But then again, the wells below have already been issued a permit from NDIC so I assume "we're" talking about different eleven (11) wells. From the linked article:

The Bureau of Land Management (BLM) has completed its environmental analysis on a proposal to drill oil wells on private land within the Fort Berthold Reservation near Lake Sakakawea. 

With completion of this environmental analysis, the BLM will approve a permit for the Slawson Exploration Company to drill the first eight of 11 wells from a single well pad.
The well pad will be located approximately 800 feet from the lake, with the production facilities located three quarters of a mile away. 

Although the well pad and facilities will be located on private land, the BLM must issue an approved permit to drill the Federally-managed leases, which will be accessed through horizontal drilling.

But it sure sounds like the same set of wells: the production facilities will be located three-quarters of a mile away, same as the site below in the "original post."

If these are the same wells, and it appears they are, this appears to be the process: the NDIC issues a permit, but if the BLM has jurisdiction, the BLM also has to approve the NDIC permit.

Original Post

From a sundry form received September 23, 2016:

Slawson requests that the referenced wells be removed from confidential status. Slawson will instead request confidential status upon completion as allowed per rule 43.02.03.31. Slawson estimates the drilling of these wells will commence in October, 2016, and last approximately 12 months. Our current plan is to drill the 10 Torpedo wells back-to-back before completion operations. Completion and clean out will last approximately 14 weeks. 

Some other notes from other correspondence:

• the wells are currently planned to be drilled with a rig equipped with a closed-loop mud system and electric motors, which eliminates reserve pits, and greatly reduces noise and emissions
• sound walls (32-feet in height) will be constructed and used during all drilling and completion activities
• completion operations will use a lay-flat pipeline system to deliver fresh water to the well site that will eliminate 600 trucks per day
• the production pad will be located offsite, approx one mile northeast
• pad location was moved north from originally proposed site to allow a greater distance from the lake ... the new location increased the overall length of each wellbore, added to the cost of each well by $250,000 for the 2-mile laterals and $400,000 for the three-mile laterals due to additional cement, tubulars, and drill days (approximately $4 million added project cost)

Proposed APD conditions allowing operation "only during the winter months will have" considerable operating and cost effects. It would also extend the complete drilling program to take 3 - 4 years instead of the 14-month timeframe described in the BLM Torpedo Federal Environmental Assessment.

Note: a water truck typically carries 11,600 gallons of water. A completion requiring 7,000,000 gallons of water translates to 7,000,000/ 11,600 = 600 trucks. [Update: see first comment -- in ND, there is a weight limit which translates to 8,000 gallons max for water. 8,000,000 gallons / 8,000 gallons = 1,000 trucks for a rather average frack.]
 
X marks the spot(s). Five sections in this drilling unit. 5 x 640 = 3200 acres, all under the lake:

The horizontals will run north to south and will fan out as seen in the graphics below:

Mix of lengths for the laterals:

Nice graphic of the area to include the town of Parshall:

Random Update On Scanlan And Pankowski -- November 26, 2014

The graphics:

 The wells:

• 33404, 2,053, Whiting, Thomas 43-4H, Truax, t1/18; cum 203K 7/19; cum 257K 11/22;
  
• 33405, 1,229, Whiting, Thomas 43-4TFH, Truax, t1/18; cum 171K 7/19; cum 2239K 11/22;
  
• 33406, 2,502, Whiting, Thomas 43-2H, Truax, t1/18; cum 162K 7/19; cum 319K 11/22;
  
• 33407, 1,633, Whiting, Thomas 43-2TFH, Truax, t1/18; cum 199K 7/19; cum 267K 11/22;
  

• 33409, 1,102, Whiting, Scanlan 42-9TFH, Truax, t12/17; cum 176K 7/19; cum 240K 11/11;
  
• 33410, 1,947, Whiting, Scanlan 42-9-2TFH, Truax, t12/17; cum 176K 7/19; cum 185K 11/22;
  
• 33411, 1,980, Whiting, Scanlan 42-9-3TFH, Truax, t12/17; cum 139K 7/19; cum 194K 11/22;
  

• 25602, 2,631, Whiting, P Scanlan 153-98-16-9-5-5H, Truax, t3/14; cum 323K 7/19; cum 338K 11/22;
  
• 25601, 1,461, Whiting, P Scanlan 153-98-16-9-11-16H3, Truax, t4/14; cum 97K 7/19; cum 140K 11/22;
  
• 25600, 2,665, Whiting, P Scanlan 153-98-16-9-5-12H, Truax, t3/14; cum 308K 7/19; cum 353K 11/22;
  
• 27122, 2,372, Whiting, P Scanlan 153-98-16-9-11-16H, Truax, t4/14; cum 242K 7/19; cum 365K 11/22;
  

• 18770, 819, Whiting, Scanlan 3-5H, Truax, t9/10; cum 367K 7/19; cum 397K 11/22;
  

• 33294, 1,600, Whiting, Scanlan 11-5-2TFH, Truax, t1/18; cum 165K 7/19; cum 256K 11/22;
  
• 33295, 1,595, Whiting, Scanlan 11-5TFH, Truax, t1/18; cum 229K 7/19; cum 25K 11/22;
  
• 33296, 2.095, Whiting, Scanlan 11-5-2H, Truax, t12/17; cum 194K 7/19; cum 253K 11/22;
  
• 33297, 1,591, Whiting, Scanlan 11-5H, Truax, t12/17; cum 243K 7/19; cum 325K 11/22;
  

• 20856, 1,349, Whiting, King 3-8H, Truax, t1/12; cum 354K 7/19; see full production data here; cum 407K 11/22;
  
• 33455, 2,454, Whiting, King 11-8H, Truax, t12/17; cum 207K 7/19; cum 274K 11/22;
  
• 33456, 1,252, Whiting, King 11-8-2H, Truax, t12/17; cum 195K 7/19; cum 248K 11/22;
  
• 33457, 1,525, Whiting, King 11-8TFHU, Truax, t12/17; cum 190K 7/19; cum 269K 11/22;
  

• 28717, 3,638, Whiting, P Johnson153-98-1-6-7-16HA, Truax, t8/15; cum 465K 7/19; cum 557K 211/22;
  
• 28715, 3,899, Whiting, P Johnson153-98-1-6-7-16H, Truax, t9/15; cum 428K 7/19; cum 511K 11/22;
  

• 31086, 2,249, Whiting, P Pankowski 153-98-4-6-7-13H, Truax, t9/15; cum 369K 7/19; cum 425K 11/22;
  
• 31087, 2,399, Whiting, P Pankowski 153-98-4-6-7-13H3, Truax, t9/15; cum 205K 7/19; cum 240K 11/22;
  
• 31088, 2,248, Whiting, P Pankowski 153-98-4-6-7-13HA, Truax, t9/15; cum 3145K 7/19; cum 366K 11/22;
  
• 31089, 2,374, Whiting, P Pankowski 153-98-4-6-7-14H3, Truax, t10/15; cum 244K 7/19; cum 291K 11/22;
  

• 20857, 358, Whiting, Pankowski 4-6H, t2/12; cum 259K 7/19; with periodic small jumps in production, month-over-month; cum 273K 11/22;
  

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

Original Post

NOTE: starting with cumulative totals in October, 2014, an asterisk should be placed, stating that producers could be choking back production starting in October, 2014, in the Bakken for any number of reasons:

• backlog in rail (BNSF said they were going to cut back on takeaway to make room for grain)
• global slump in oil prices
• tsunami of oil arriving at destinations
• North Dakota flaring rules go into effect 

18770, 819, Whiting/KOG, Scanlan 3-5H, Truax, t9/10; cum 285K 12/17; updated here;

20857, 358, Whiting/KOG, Pankowsi 4-6H, Truax, t2/12; cum 240K 112/17;

25599, dry, Whiting/KOG, P Scanlan 153-98-16-9-11-16H, c11/13; cement casing failure on surface spud;
25600, 2,665, Whiting/KOG, P Scanland 153-98-16-9-5-12H, t3/14; cum 238K 112/17;
25601, 1,461, Whiting/KOG, P Scanlan 153-98-16-9-11-16H3, t4/14; cum 83K 112/17;
25602, 2,631, Whiting/KOG, P Scanland 153-98-16-9-5-5H, t3/14; cum 281K 112/17;

This is what this area currently looks like:

One can tell from the map, that there is a lot more room for a lot more Scanlan wells.

I "wish" NDIC would make a distinction between "truly dry wildcats" and wells that were not completed due to operational issues, not that the well was "truly dry."

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

A Note For The Granddaughters

I remember when I was the manager for our high school football team. I was responsible for tracking rushing and passing statistics (among a whole of other things). I was never told how to do things, "just do it." (Nike.) So, when it came to passing, I tracked the yardage of the pass itself, and then the yardage gained after the pass. My coach thought I was nuts. He just wanted the "passing yardage," and he didn't want it broken down into two elements. I see now, the NFL and the television broadcasters break it down the same way.