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Permalink Reply by Mark on July 10, 2019 at 3:02

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

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Permalink Reply by Skip Peel - Mineral Consultant on July 10, 2019 at 3:05

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.

Permalink Reply by Rock Man on July 10, 2019 at 4:32

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.

Attachments:

• EF decline.pdf, 109 KB

Permalink Reply by Rock Man on July 10, 2019 at 4:41

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.

Attachments:

• Decline Curve Jan 2019.pdf, 145 KB

Permalink Reply by Mark on July 10, 2019 at 5:07

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. 

Permalink Reply by Rock Man on July 10, 2019 at 5:52

(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.

Permalink Reply by Dion Warr, CPL on July 11, 2019 at 1:53

RM:

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.

Permalink Reply by Robert Craft on July 31, 2019 at 3:29

COP Louisiana Austin Chalk article from Fuelfix:

https://www.chron.com/business/energy/article/ConocoPhillips-disapp...

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Permalink Reply by Rock Man on July 31, 2019 at 4:21

That's a pretty condemning news article for the play - at least in the areas where CP has been active and drilling. Discussing the TMS as an alternative here doesn't make me feel any better either considering the difficulties with that play.

CP's comment about focusing on the Permian Basin makes sense considering their position - there they have "proven reserves" and just need to put capital into those areas to exploit it.

In saying all this, a major spending several millions of $$$ for acreage and drilling / evaluation in a new play area is typical. I have seen it across the USA and overseas in many different plays.

Now the questions is - What about the other operators in the La Hz AC play??

PS - Expect an update from Kirk on his site about CP's position.

Permalink Reply by John Matherne on July 31, 2019 at 4:23

Down dip time

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Permalink Reply by Rock Man on July 31, 2019 at 4:27

There is a LOT of area in this trend - a few wells will not evaluate everything.

I remind everyone about the Tx AC Hz Frac play - the Karnes County sweet spot that EOG and others are exploiting with great success is less than 30 miles from dismal results on trend in an adjacent county.

Mother Nature's relative ("Cousin Geology") can be very fickle and unpredictable.

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Permalink Reply by Robert Craft on July 31, 2019 at 9:17

McKowen: 350 BBL oil produced on the May 1 report.

http://sonlite.dnr.state.la.us/sundown/cart_prod/cart_con_wellinfo2...

Hebert: 1538 BBL oil

http://sonlite.dnr.state.la.us/sundown/cart_prod/cart_con_wellinfo2...

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