So, is that it? Are we done?

     I noticed that there is not much activity here on the western edge. I would like some input as to whether the oil companys gave up until new technology is available to squeeze the oil out in the Utica or the price has to go up. There are a lot of people out there with the knowledge of how these companies act in these cases.

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0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on May 23, 2013 at 8:41am

Assuming my aunt had balls she'd be my uncle. 

0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on May 23, 2013 at 9:10am

Right, and there are how many more like that one?  Two?  Six?  These monstrous conventional wells happen and they're a coup for everyone involved, but you cannot rely on that as an example of what production can be anticipated.  What's the API# for the well?  You've got me all intrigued now and I want to do a little research.  If there's a conventional well with that kind of production there has to be a structure in place there.

0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on May 23, 2013 at 8:46am

Also, what discount rate did you use per year?  Because that will change the numbers dramatically. I just plugged some numbers into one of my projections.  40,000 bbl/yr. with a 15% annual decline.  Prices @ $90/bbl.  LOR is 12.5% with PV10.  A 13 year spread gives you two different numbers: $2,800,000 for gross LOR.  NPV (net present value) of LOR is $1,800,000.  So that PV10 discount over 13 years costs ~$1,000,000 net to the landowner. 

0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on May 23, 2013 at 9:38am

No, I'll dig around from here.  Thanks.

Permalink Reply by dan gladyszewski on May 23, 2013 at 1:31pm

Man, Jodi, you're smokin today!! In this horse race, I think you're leading by a length. I respect both you and Marcus' opinions and thank both of you. I also thank everyone else that has input so far. Right now, I'm leaning that there is something worthwhile down there that O&G want.  Aside , from kinfolk's genitalia, (LOL) I am learning a lot. Can't wait to see where this goes.

Permalink Reply by Billy Park Whyde on May 23, 2013 at 4:35pm

When you consider the cost of a vertical well vs a horizontal I think we are in for a surprise be very quite hunting those rascally land owners in the dark, lol. 

Permalink Reply by Thomas Moss on May 30, 2013 at 9:14am
best secret in ohio. i have been on a few roserun crews. they are hard to hit. i talked to a guy last week about this. he said 3d siesmic will make it like shooting fish in a barrell in a few years. he said it getting better and better. i would think at 4000 feet that makes it even easier. you must have made marcus blush or the cat got his tongue.
0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on May 30, 2013 at 9:34am

I answered her question in a private message.  Anything else I can do for you?

Also, I'll give you all the money in my wallet if you can ever find any post that I made concerning the long term inviability of Rose Run, Trempealeau or misc. Knox formation wells in the Knox/Licking area.  Take your time.

Permalink Reply by Jim on May 23, 2013 at 4:02pm

Yes, this has been a good conversation.  I laugh everytime I read the reply from Marcus about your math. 

But Dan, this is a good question because everyone is focused on the area two counties wide that border the eastern state line from north to south.   But I think a county or two east and west of Central Ohio is where the oil opportunities will be found.  It will take infrastructure before that area opens. 

0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on May 24, 2013 at 1:28am

It was about your math Jim, not Dan's.

Permalink Reply by Kangoo on May 23, 2013 at 9:55pm
This article confuses total depth and horizontal lengths. The numbers for horizontal length mentioned are total well depths, meaning the vertical section and the horizontal section. Average horizontal length to date has been around 6000 ft in Utica, with wells more and more moving towards 7000 and 8000 ft horizontal length, since the economics are better for longer horizontals....
Permalink Reply by Kangoo on May 23, 2013 at 10:14pm
Jack,
Mud motors don't change physics. One needs the weight from the vertical section to overcome the drag in the lateral section.
A 6000 ft lateral at 1400 ft TVD would be extremely difficult with today's technology and nothing like this has been drilled in any onshore US play.

Mud motors are mostly used for steering (they call it slide mode). Once you are in the lateral most drilling is done rotary style. The current state of the art (best performance, but also more expensive than directional assemblies with motors) is actually 'rotary steerable technology. Here you no longer have a motor at all, but orient the drill string by applying side forces and all rotation is done again at surface via your topdrive....

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