Friday, October 10, 2014

Monster "Snake" Wells In Antelope Oil Field -- October 10, 2014

Updates
May 22, 2020: these monsters well updated.

January 11, 2019:
  • 32832, 1,710, Enerplus, Garter 152-94-18A-19H, Antelope, t9/17; cum 387K 3/20;
February 19, 2017: compare the screenshot of the map taken today with that taken at the time of the original post. Current map:




November 29, 2015: the Bull and the Rattle wells are huge!

June 17, 2015: production update for the "Ribbon" well has been posted.  

Original Post

Yesterday I mentioned that Enerplus was going to report a "monster well" today. I was wrong. Enerplus reported two "monster wells" today.

At the bottom of that post I have a screen shot and asked readers if they saw the same thing I was seeing.

Yesterday I was impressed by the fact that the immediate area in which this well was drilled has had a spectacular history with some great wells. Some wells drilled back in the late 1950s are still active (rare); and many of the wells (drilled from the late 50's) have/had a total production of almost 1 million bbls of oil, many from two payzones, the Madison and the Sanish. 

In the big scheme of things (look at the Grail, the Truax, the Parshall, the Banks, the Sanish, etc) this area has hardly been touched with horizontal wells. (Compare the Truax screen shot at the very bottom of this post.)

But now that I've seen the file report, this well has even more surprises. 


First two screen shots.

The first screen shot provides an overview of the general area:




The second screen is a "zoom in" of the four Enerplus wells, two of which reported results today:



The wells of interest:
  • 4240, PA/AB/391/25/45, Hess, AMU H-517HR (a re-entry well), Devonian/Sanish/Madison, t5/67; t7/91; t10/06; cum 206K (6/91); 3K (5/05); 75K (12/16); as far as I can tell, never fracked; went inactive on/about 4/14; back on active status 6/15; inactive 8/17;
  • 18435, 2,376, XTO, Nelson Federal 41X-5G, Sanish pool, 11 stages; 1.3 million lbs sand/ceramic; t3/11; cum 337K 3/20; went inactive 5/15; back on status 1/16; off line 10/18; back on line 4/19;
  • 24337, 2,519, EOG, Hawkeye 3-2413H, Antelope-Sanish pool (all EOG paperwork says "Bakken" but "Sanish" is inked in on most recent sundry form -- this is a Sanish pool well); 28 stages; 9.7 million lbs sand; t5/13; cum 817K 3/20;
  • 26737, 3,374, Enerplus, Ribbon 152-94-18B-19H, Sanish, again, much of the paperwork says "Bakken," and the target was clearly the middle Bakken (middle Bakken "C") but the scout ticket says the Sanish pool; 42 days (316 hours) of drilling; 42 stages; 10.0 million lbs sand; t4/14; cum 650K 3/20;
  • 26990, 3,102, Enerplus, Hognose 152-94-18B-19H-TF, Sanish, specifically Three Forks 2nd bench, three laterals; 60 days (533 hours) drilling, 41 stages; 9.7 million lbs sand; t4/14; cum 573K 3/20;
  • Hognose 152-94-18B-19H-TF
  • Hognose 152-94-18B-19H-TF-ST1
  • Hognose 152-94-18B-19H-TF ST2
***************************************

Formation tops / stratigraphy for the Ribbon well (#26737):

 **************************

Formation tops / stratigraphy for the Hognose well (#26990):


Note the markers, "A" through "E" for the middle Bakken. I've seen these markers in other well reports. Note the thickness of the middle Bakken, TVD (10,359 - 10,318 feet = 41 feet).

On the log reports, the formation tops (TVD):
  • lower Bakken shale: 10,359 feet
  • Three Forks - 1st bench: 10,383 feet
  • Three Forks "RT": 10,419 feet
  • Three Forks - 2nd bench: 10,431 feet
Three Forks thickness, 1st bench: 36 feet

***************************************** 
For The Archives

Compare the development of the area of the Antelope oil field (noted above) with the development of a small area of the Truax oil field -- this is what surprised me most by the snake wells announced today. This screen shot taken the same day as the other screen shots above:

4 comments:

  1. This whole general area of the reseveration is very early in production. Watch the Spotted Horn Field just south of the Antelope. EOG has some very good wells already and has had hearings asking for up to 64 wells per drilling unit!!! Enerplus has both of It's rigs drilling on drilling unit of 150-94 29 & 32. My wife and I are heading up to Fort Berthold at the end of this month and will send some pictures of his area if you would like to see them.

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    Replies
    1. Thank you; readers always enjoy photographs. I am only limited by how much I want to pay Google to post photographs. YouTube videos are free, but photograph "storage" comes with a fee, albeit quite small.

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  2. how come the CLR IPs in the "ears back" Antelope are so crappy (200-300) versus those awesome IPs (2000-3000) from other drillers? Same field, no?

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    Replies
    1. You are correct: it is the same field. One can see the wells in the Antelope field at his site:

      https://www.dmr.nd.gov/oilgas/findwellsvw.asp

      I think there are at least two factors (and probably others) for the differences in IPs:

      a) geology: note location of CLR's wells in the Antelope field compared to the monster wells reported by by Enerplus today (NDIC GIS map server); it's quite remarkable

      b) I don't believe CLR has started using the new completion techniques discussed in most recent CLR corporate presentation; on the other hand, Enerplus use high (actually very high) proppant volume completion techniques.

      But generally speaking, across the entire North Dakota Bakken, CLR reports lower IPs than other operators in the same area. In this case (Enerplus Antelope and CLR Antelope) is incredibly different, but I think it is mostly due to location (graphically displayed on the NDIC GIS map service) and completion techniques. My hunch is that even high-volume proppant completions in the CLR wells in the eastern Antelope might improve CLR's IPs in this area, but won't come near to what Enerplus is reporting in west Antelope.

      It goes without saying that I do not know the parameters Enerplus uses to test wells/report IPs nor the parameters that CLR uses to test wells/report IPs.

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