Depletion "Type Curves" from company websites show a dramatic drop in production after one year
The "Type Curves" from many of the company presentations seem to indicate that the gas/NGL output from horozontal wells will fall by ~75% within one year, and oil by ~50%. Page 36 from the Antero presentation is one example. Am I intrepeting this accurately? Any comments will be appreciated.
http://www.anteroresources.com/wp-content/uploads/Company%20Website...
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Replies to This Discussion
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Permalink Reply by The Hiker on
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Agree. He's quite a smart guy! Understanding NGL's and the economic decisions surrounding ethane rejection is a daunting assignment. His spreadsheets and explanations of the variables they have to juggle helped clear it up a bit (still a bit muddy), but I get the general drift. Interesting subject.
I wasn't aware that propane was used in the refrigeration plants to "chill" the gas; (another deduction from your check?)
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Permalink Reply by 0i7okn54zwbdo on
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Did he happen to mention any realized prices per BOE that they're getting here? I've been trying to nail down an estimate but I don't have all the needed data points.
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Permalink Reply by Bluflame on
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Marcus,
Mr. Palm emphasized that they only have two wells (Wagner & Boy Scout) on line into a sales stream at this time. He said even with those GPOR had been experimenting with various flow rates to maximize overall recovery. He also believed all wells will be on line by June as MarkWest completes their processing facility and especially their gathering lines. So, not much about realized pricing since so little product has flowed to the market.
He made a big deal of their plan to ship condensate to Alberta, Canada to be used as a diluent in the tar sands pipelines transporting oil to the Canadian west coast. Gulfport has a significant stake in that business.
Too much info in the 1+ hour analyst call to remember/outline all of it. Suggest it's worth your time to listen to the transcript of the call. 90%+ dealt with the Utica.
BluFlame
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Permalink Reply by Dan on
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One thing that caught my attention was that along with the experimenting they are doing with various aspects of the process, they are going to be trying out smaller lateral spacing. 1000' spacing between laterals has been the rule of thumb, assuming that migration can occur up to 500' away from the well bore. If it turns out that this is not the reality, and the IP numbers we are seeing are happening from a migration limit much less, like 250', then that would be significant. It could drastically increase estimates of total yield per acre. It will something worth following.
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Permalink Reply by Joseph-Ohio on
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It stands to reason that more laterals would do a better job draining the resource.
But, the downside would be the increase in drilling / development cost.
The economics would also depend on how much resource exists to drain.
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Permalink Reply by Bluflame on
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Hello Dan,
GPOR has advocated closer spacing in their last few quarterly updates. One new thing I heard in the call was that the laterals in the "experimental well" would be in a "fan" pattern instead of parallel. They would then experiment with various fracking techniques in the individual frac stages. They plan to place monitoring devices along the frac paths of the "fanned" well laterals with the objective of finding out which combination of spacing and frac technique results in tapping the entire space between laterals.
This seems like an ambitious undertaking and will likely require multiple well experiments to come to any valid conclusions. I wouldn't want my property involved in such an experiment without some royalty guarantees from GPOR. I wonder if and/or how they will deal with lessee concerns?!?! I've never heard of any "experimentation" provision in anyone's lease.
BluFlame
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Permalink Reply by LERRET on -
One big issue in shales is that it is relatively easy to "frac into" an adjacent well, thus comingling production. I have seen several such wells in the Fayetteville where a well suddenly sees a pressure and volume change once another well is drilled nearby.
In Kansas an experimental injection program ran by the state injected carbon dioxide in an existing field. None of the nearby wells were seen to increase production, but about 2 miles away a well outside the experiment saw a sudden rise in production, doubling in a matter of weeks. The carbon dioxide had bypassed the ring of wells around it and went along a fracture between two wells and beyond.
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I guess that's where the different types of shale come into play. Some shales are more or less dense than others I suppose, and that would affect the optimum lateral spacing, or frac stages intervals, or any of several variables they can play around with to customize the the drilling for the shale they are in. Even within the same shale formation it can vary somewhat I suppose.
With regard to the risk of the mineral owner who is being experimented on, it would seem fair to work out some special deal, since an experiment gone bad could lower their royalty. They could either agree to a fixed payment no matter what based on adjacent production, or they could choose to share in the risk and rewards, since it is possible that they could hit upon a technique that gives them higher production than they would have gotten.
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Permalink Reply by Joseph-Ohio on
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Bluflame, Lerret, Dan,
The way I'm reading things, Lerret's and Dan's posts are the only / most plausible reasoning that I've read favoring / in defense of drilling units larger than 640 acres.
The downside is still the dillution of landowner royalty payments.
It seems to me that which works out to be better / worse for the landowners involved would vary with the specific wells / acreage / geology involved.
Don't know how or if it would even be possible to predict the best scenario.
Maybe it's possible pending the specific geology.
? ?
Not being a geologist and not knowing what to do in all cases to me still is a strong enough reason to leave 640 acres as a maximum drilling unit size.
What do you fellows think ? ?
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Permalink Reply by Joseph-Ohio on
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Jay, I'll take this as an opportunity to write that I've got my suspicions pertaining to 'shills' on these pages - but I don't think they think that I'm savvy enough to know that folks like that exist.
Most folks take me for a naive' type of guy and are forever trying to pull the wool over my eyes.
I am at my most stupid when I (initially) give the other guys the benefit of any doubt.
I'm working on that flaw.
Thanks for all of your posts.
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Permalink Reply by Bluflame on
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Jay et. al.,
I've read accounts (particularly from Gulfport) about the possibility of 250' spacing. And (so far), I'm impressed with GPOR's technical expertise as demonstrated in their monthly updates and Mr. Palm's analyst comments.
Contrarily, I'm no expert on well spacing. LARRET's posting above notes problems in the Fayetteville Play with fracking intruding into neighboring laterals. And Dan notes the shale rock differences between the plays as a factor. Both of those concerns seem plausible. So I endorse GPOR's plan to experiment scientifically to determine the optimum combination of fracking & lateral spacing for the Utica. In other shale plays, their answer may be different.
At the end of the day, all parties benefit from extracting the maximum hydrocarbons from the shale formation with the minimum number of laterals. The former objective supersedes the latter.
And J-O, IMHO, the unit size is somewhat neutral in determining return to landowners. In theory, while the landowner's % share of the overall unit will diminish with a larger unit, the number of laterals and length of the laterals both increase, thus increasing overall production and neutralizing royalty payments. In practice, it's a "you never know" syndrome. Again, optimization of well spacing & fracking techniques seems to me to be the most important factor, and GPOR seems to be on this "Like a hobo on a ham sandwich"!
BluFlame
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