Anyone have any new information

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I’ve got 100 acres between the McKowen and the proposed well on the Blairstown road directly south of the EOG well. All are within 6-7 miles as the crow flys. We haven’t been contacted. Who knows

I think Infill leasing will commence quickly in proximity to any and all successful wells.  If your parish clerk of court has a remote access account, I suggest that you get a subscription.  Several can share in the cost.  Louisiana is a "race" state so lessees can not sit on leases indefinitely without recording them in the public record.  I would actually prefer to be un-leased at this point in the play.  If operators figure out the key to economic wells, the lease offers should improve significantly.  Especially for those close to the economic wells.  Sharpen your pencils and keep up with developments.

And if things fall you way, consider a donation to

I’m sorry guys. I’m a common core mathematician. Public school education in the Obama years. 

Well the McKowen is a dog for whatever reason so that’s not looking good. The second well COP drilled isn’t looking good. I’m not counting on much. 

I think we land owners for the most part don’t understand the difficulty oil companies have making money at this price in this business environment. There is oil and gas in these formations but is it commercially viable? I used 58$ a barrel and if well costs are 10 million a well and that’s extremely optimistic by my calculations the well would need a IP number in the 1500 or higher range to pay for itself in a year to 18 months and I may be low. I’m hoping Skip or Jay can give us a guide with what we can look for

I'll defer to Jay on that question, Mark.  I do think it is worth noting that in addition to production volume, well cost is important.  And that early wells tend to be significantly more costly than later development wells once a play has been proven economic.

Following comments aren't from Jay but this may help understand the economics on something like this.

Regardless of the IP rate for these wells, there will be production decline over time - and it probably will be rapid if the AC follows other "unconventional" stimulated reservoirs in how it performs. The EOG well is a prime example of how quickly IP production turns into a situation where only 10-20% of the IP volume is being produced.

I have attached an Eagle Ford production decline example to illustrate this concept. Months on "X" axis and production decline (cumulative monthly decrease % of initial month's rate) on the "Y" axis. Note that after 12 months, production is less than 30% of the initial months volume.

So using the 1500 BOPD IP number, you are looking at production in the 450 BOPD or less scenario at the end of year one. And still declining until you get to a "flat line" volume in the 5 to 10% of initial production range.

This hyperbolic decline will of course vary depending on a large number of factors, but it will happen in this plays - including the AC Hz Frac play.

Same scenario goes for the TMS in this same area / trend. 

Tack on monthly operating costs (including SWD, artificial lift), subtracting royalties & production taxes and you end up getting slimmer margins. 

Any economic analysis for an operator will include looking at the discounted value of the production stream over time - not the undiscounted totals. PV (present value) and ROI (rate of return) are important - is it better to keep money in the bank and earn whatever interest or put it in the ground as D&C capital? Or put the capital into better performing play areas?

The O&G world is full of play areas and concepts that produced O&G - sometimes in very good volumes - but that did not make money for the operators for various reasons. Royalty owners get their payments regardless, but operators have to turn a profit.

The Cline Shale "boom" in the Permian is one that jumps to mind - great O&G in place but operators have yet to be able to crack the code to make that play economic. Pearsall Shale, Goodland Lime, Collingwood Shale, etc. all fall into this category.

Hope this helps.


PS on my previous note - attached is the similar style production decline curve from the EOG Avoyelles Parish AC well. I presented this initially at the NARO meeting last summer in Marksville.

Note the very rapid decline from initial month to the end of 12 months on this well (about 95%). This well has settled in to a pretty flat rate.

Admittedly, one would not expect the best results from the first well in the play area (like this EOG well), but it is indicative of what one may expect from this reservoir.

Of course, the better the reservoir and stimulation approach, the better the results. The Tx version of this AC play is a good example of this. The EOG Karnes Co area is a beast as to production and economics - but move one county over into Gonzales Co and you get dismal well results.


I used 35% as royalty and operating cost. I also used 60% of production for the year inthe first 90 days. I worked Chalk wells out of Snook Texas for several years in the early 80’s. Actually I could have said 60% for the first 60 days and still been pretty accurate. 

(Replying to your comment @ your AC metrics. / no reply option at the end of that discussion thread)

Those Tx AC wells around Snook / Giddings et al were a real hit and miss situation due to that being the natural fracture AC play. Those fractures - where persistent and extensive - made some great wells.

Different play here with much more expensive wells and steeper decline and higher operating costs. ESP's and trucking SW @ $2 per bbl add up against the bottom line.

Hopefully the operators in the trend will ID the "sweet spots" (assuming that there are some) that will give up high O&G rates post frac to support those areas economically.


Based upon large frac fluid injection volumes (and corresponding return and "clean up"), would it not be a considered option to opt for annular disposal or a SWD well?  It's a SWAG, but I would estimate a lease/unit SWD could cost approx. $650K to complete and equip to an appropriate disposal zone (e.g., Frio) which based upon your estimated trucking cost ($2/bbl) would become economic likely within the first month or two of operation.

There doesn't seem to be a lot of support for a commercial SWD in the area at the moment (from the operators or the land / mineral owners), but an "on lease" SWD should be - and was SOP in the Gen 1 wells (mid- to late-90s) and done nearly side-by-side at that time.

COP Louisiana Austin Chalk article from Fuelfix:



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