Replies to This Discussion

Permalink Reply by Bobi Carr ("parker") on September 26, 2013 at 4:50

Jay,

At today's price, what EUR is necessary to be economic?

Also, what would the figure be at 24 months of production?

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Permalink Reply by w.r. frank on September 26, 2013 at 17:58

What strikes me are the commonalities:

E/W= 12W

Operator: HK

Don't agree with Jay on Sabine. I would take Guffy in a NY minute. Agree in Natch.

Now why does HK do better? I have royalty in six units. Only one operated by HK (yes, it is in 12W), but CHK and Swepi SUCK in adjoining sections compared to HK (yes, all three units are in 12W).

Are they better operators? Better frac design? Spend more on proppant? What is the secret sauce? My guess is HK did a more expensive frac; length, sand, prop pant. intervals, etc. CHK cheaper it to just HBP the unit. SWEPI, who knows? Less than a third of HK cumulative production at each time data point!

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Permalink Reply by adubu on September 27, 2013 at 0:58

SG--- how has IP compare/predict to the EUR after 4-5 years production?

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Permalink Reply by Skip Peel - Mineral Consultant on September 27, 2013 at 3:43

adubu, although I have not been collecting the data for comparison I have noticed that the relationship between IP and EUR has a very large variation across the Basin.  I would say that IP is generally a poor predictor of EUR.  This is becoming more apparent as Cross Unit Laterals in LA and extended length laterals in E TX are drilled.  Many wells with 3 to 4K feet of lateral have IP only slightly less than those with 7K feet however the EUR is often almost double for the extended lateral wells.

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Permalink Reply by Dion Warr, CPL on September 27, 2013 at 5:19

Skip:

I feel that you are comparing the proverbial non-similar fruits.

 

I think that one would hope that twice as much pay zone contact of perforated wellbore would yield approximately double the EUR.  Otherwise, one would not realize the cost savings of drilling one vertical and building one radius for two units instead of two, given the costs of horizontal drilling and frac jobs remain relatively constant per foot and per frac, respectively.

 

Also, formation pressures would not similarly double, as the amount of overburden and formation overpressure would remain more or less constant at a given depth and near proximity.  In many cases, posted IPs are "spontaneous", as they are calculated at well test based upon cross-sectional area of the production line and line pressure.  This presented a problem in analyzing early wells, as different operators utilized different procedures and reporting criteria - e.g., some results were "popped" as spontaneous IPs which did not reflect in 30-day, 90-day and 120-day analyses, whereas "24-hour" production tests had better correlation.  Les B posted some good work on this before.

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Permalink Reply by ledlights on September 27, 2013 at 7:08

DW,

The study (this link is a summary - if you click on this link it may ask you to signup/login - if you search the article title via google you should be able to get to the full article) released this summer on the Barnett by the UT Bureau of Econ. Geology, found a general decline in EUR per lateral ft. beyond about 3000 ft. The graph in the link above makes that decline look pretty steep. I am not even remotely capable of factoring in such variables as the Barnett being on the early end of horizontal fracture development, the differences in the Barnett shale geology versus other shales, etc. 

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Permalink Reply by Skip Peel - Mineral Consultant on September 28, 2013 at 12:48

Dion~

I'm making a cursory observation that I have not researched specifically.  However I have noted a number of instances (five years worth) that support my point, regardless of fruit variety. :-)  IP's do not correlate very well to EUR.  My point is that IP is a poor data point.  It has received far too much emphasis in our discussions for the simple fact that for so long there were no other metrics available.  Now that we can view three to five years worth of actual production, IP is largely insignificant.

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Permalink Reply by Mark Hughston on September 27, 2013 at 4:12

You obviously have not run eur's on these wells.  the cum to date has a lot to do with the quality of the well, but also has a lot to do with how old the well is. Take a look in Sabine Parish at the Olympia Minerals 4H and a number of other wells in that area. The Encana  4H-2 well (they drilled and lost the 4H-1) has made 4.8 BCF in 13 months and makes 7.6 MM/Day.  According the Swepi, a 50% owner of the well, one of the best wells they have drilled in the entire play

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Permalink Reply by Mark Pomeroy on September 27, 2013 at 5:19

"I am not a reservoir engineer."

That fact may give you a leg up.

 

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Permalink Reply by adubu on September 27, 2013 at 6:34

Jay-- sorry I open a hornet's nest but discussion of information on EUR is interesting --- IP it appears to not be a good indicator since choke, length of laterals,pressure,  location of well, etc all play a factor in calculation of EURs. So maybe question should be what's the best way to get a good EUR on a well? Do We have any Reservoir Engineers members on GHS or anyone with knowledge but not necessary degree in Engineer?

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Permalink Reply by adubu on September 27, 2013 at 8:07

Jay--- agree with all you say re: EURs--- so question ---is there a good way to calculate the EUR on any given well ( i.e. what does the Engineers use to calculate same?)

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Permalink Reply by ledlights on September 27, 2013 at 8:51

Adubu,

There have been discussions (see this one) on GHS about this in the past. My interest in particular was to try to project yearly payments for wells my family will get royalties from (using what I think is a conservative estimate of gas price - but that is another WAG). All most of us can use to do that has been IPs and whatever kind of generalized decline curves have been released to the public. I created my own spreadsheet to approximate that curve and posted it here and D. Gaar posted one. There may have been others. Mine was based on the old, steep at the beginning but flattening with a long tail out curve (unproven) that was available 3 or more years ago. If I input the Black Stone well (IP 29 MCF) I get a EUR of 11 to 13 BCF depending on how long it stays productive. The Hutchinson well (IP 23 MCF) projects maybe 10 BCF EUR. Both of these wells have produced over 3 more BCF than my spreadsheet predicts at 4 years of production. I am not inclined to trust the old decline curves that I used, but then maybe differences could be explained by lateral length and other factors specific to individual wells. I would assume that engineers have much more detailed input for their projections, but wouldn't those typically be proprietary methods?

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