Thursday, January 10, 2013

EOG Dupuy 20H-1 - IP Discussion

I knew that when I posted the estimated economics for the EOG Dupuy 20H-1 it would generate some discussion. I have received many emails and calls about it.  The main question is why my initial potential is different from the one released on SONRIS. I posted my information on 1/4/13 prior to the SONRIS posting of the initial potential on 1/7/13.  My value of 650 bopd was provided from a good source and it closely matched the allowable that was posted on SONRIS (656 bopd on 11/30/12).  The GOR of 700 was also provided from a good source.
EOG Dupuy 20H-1 (Source: SONRIS)
From what I hear, the well has averaged close to 500 bopd over 22 days on a small choke.  If that is accurate, with a GOR of 700, the IP30 should be around 560 boepd.  That is lower than my estimate of 785 boepd made on 12/3/12.

I've been asked by many if I think that operators release lower numbers on purpose.  The guidelines for initial potential reporting are very loose. In this play with the acreage mostly leased up, I don't see any reason for that.  The table below compares the IP vs IP30's for the wells.  There is no real trend.  In shale plays, I believe that the IP is not very important.  While it is the first data point, I believe that the first really relevant data point is the IP30.  It illustrates real production over a month.  When you compare IP's or IP30's between wells, choke size is important.

Even more important is the IP180 representing six months of production.  The Encana Anderson 17H-1 has an IP180 of 72755 BO and 23354 MCF.  The Encana Anderson 18H-1 has an IP180 of 89391 BO and 28051 MCF.  I consider those to be impressive.

My well costs of $10.3 million has also generated questions.  Daily rig rates and frac costs on a per stage basis are well known, so calculating costs is fairly straight forward.  I presented some play economics several months ago using $10.2 million.  I believe that EOG will quickly have costs below $10M on Dupuy offsets.

Those that have followed this blog since March, 2011 know that I don't post hearsay and rumors.  I prefer to post information once I feel confident that it is accurate.  I also provide technical information to support it.  There are many chat websites where you can go to get enthralled with rumors.  That is not the goal of this website.

Those that are viewing this blog to gain confidence in purchasing public stock of TMS operators are advised to do your own research and investigation.

The comment box below provides the opportunity for anyone to join the discussion.  If you're really bold, post under your real name.  Those anonymous internet names remind me of the old CB Radio handles in the 70's.  With that, I conclude with "10-4 good buddy.  I'll be 10-10 on the side".


  1. Kirk:

    Your posts as always continue to be conservative, professional and accurate based on the data available. Hard to believe, any that are familiar with your work, would question its validity.

    In fact your estimated cost of $10.3 mill is quite a bit higher that than the reported cost that was told to me by a very reliable source.

    Thanks for your continued efforts to provide critical information that is used by both insiders and outsiders alike to keep abreast of the continuously changing and improving commerciality of the TMS.

    Hopefully, when the mineral owners and industry really start reaping the economic benefits, everyone will remember to contribute to your favorite charity for the debt of gratitude we all owe you for providing the voluminous technical data that is helping all involved.

    Take care,

    John Parker

  2. What happens when you plot actual BOPD instead of BOEPD? It becomes really misleading at times with just BOE because a well with no oil can look the same as one that is 100% oil unless all the numbers are presented (i.e., both the MCFD and BOPD). In my opinion, it has really become a PR gimmick more in line with an "investment analyist" than an oil and gas professional.

  3. TulsaDeco:

    When you look at Amelia Resources Jan 2013 Play Overview on Page 18,titled Targeted Economics, the plotted curve and the Case 1, 2, 3 and 4 Scenarios all appear to be based solely on bopd (just oil).

    Given that fact, I do not understand how you think these calculations are a PR Gimmick.

    If I have mis-interpreted these charts and information, please enlighten me to my mistake.

    Thanks John

    1. There is a $3 MM horizontal well making 2,000 BOE/d in here Kansas. The problem is that it is 12 MMCF/d. So instead of making $164k/d, it is making $35k/d.

    2. Sounds like the producer needs to contact a good chemical company to get a specialized chemical solution to help well produce more oil.

    3. Actually, it sounds like the operators in Kansas may need to get on down to the TMS where they can produce some oil instead of gas !!! Now getting some "specialized chemical" to turn that Kansas gas into oil, Hmmmmm, the Gimmick of the century. Maybe Sandridge might be interested in trying that accross their very large position up there. Just might get the stockholders off Tom Ward. LOL

      Thanks John

    4. Looks like TMS wells produce a lot of water so I think "specialized chemicals" could help those wells out with more production, maybe a surfacant and emulsion breaker to get oil in fracs. Not a gimmick-it is a win-win and since it is a new unconventional play with new tech eventually want to get it right. I guess you are right about Kansas well, can't make a gas well into an oil well.

    5. Most of the water you see now is still frackwater coming back up IMO.

  4. Kirk:

    Been following... been reading... newbee to the play and industy. I'm an outsider looking to have inside knowledge. Been reading your blog since late 2010. Been looking up acronyms since then, still a little lost with some of them, but thank goodnes for Google. Anyway, I'm curious as an investor. Let's say everything takes off, all systems go. I'm a simple guy, how many TMS wells would be possible to drill in one section of land? I can't seem to figure that out and I'm tracking capital expenditures of the major players, who are keeping everything close to their chests.

    I have confidence in everything you've put forward on your blog, I find it insightful and very useful. Looking forward to contributing to some of the charities you have supported.

    Clem Moore

  5. I know your question is for Kirk, but I can tell you what at least one current TMS operator has told landowners who have producing TMS wells - they say they plan to drill 8 wells (2 pads with 4 wells per pad) on a 1200 acre unit. I believe wells will be drilled every 150 acres as the initial plan assuming all goes well. Since a Section is 640 acres then it looks like about 4 wells per Section. In the Eagleford Shale it is closer to a well every 100 acres with some operators planning wells every 90 acres. Hopefully in the TMS they will be more closely spaced eventually - this I assume depends in part on how far out they are able to successfully frack. I know that they have microseismic tested some of their frack jobs ,so, that information may be forthcoming.

  6. Kirk
    Keep on posting your great information and analysis. It has helped our group tremendously. We appreciate it. My wife and I will continue to contribute to your charities that you support and when our group gets a lease, it will also.
    Charles Bell, Manager
    Peterman Mineral Holdings LLC

  7. Free Medicine:

    The spacing information you stated above agrees with the spacing information EnCana set forth in their Forced Intergration requests and the final orders approved by the Mississippi Oil & Gas Board.

    And like you also said, it is highly probable that down the road a few years or maybe more, they will downspace the wells into the 90 acre or less range to get maximum recovery and efficiency once they have gotten the acreage positions into HBP (Held By Production) status.

    Have a good day,

    John Parker

  8. Now this is what I call an open discussion...Love it!
    Clem, rookies are welcome and encouraged to participate. With regards to spacing, we don't know yet. Encana has permitted additional locations in the Anderson unit (Amite, MS) so that might be where we get our first data back. Well spacing is all about extracting the most reserves in a cost effective manner. You don't want to use more "straws" than you have to. These "straws" are expensive. Keep an eye on the Anderson unit for development there.

  9. Charles,
    Very much appreciated!

  10. one other parameter is that once the play gets to the "resource hub" stage, many dollars will be saved by using one location.

  11. Thanks for keeping up the great data and discussion for all to see.

  12. Kirk,
    Haven't all the TMS wells so far produced about 95% light sweet oil. Would that make the difference between bopd and boepd almost irrelevant in the discussion of whether the play will be deemed economic or not.

  13. FM,
    that is correct..almost all oil