Is anyone still monitoring this site? Maybe things will start picking up again.
I am set up for notifications of new postings but haven't seen anything for a LONG time.
Figure this site is essentially dead
I monitor it daily. I guess there'll have to be some kind of precipitating event to kick things off.
Geopolitical crisis seems to be about the only thing that could bump oil back to even $60/bbl.
Pending some uptick in Oil Patch or EF Forum activity, I do wish all a Merry Christmas and hope we get out of this Chinavirus Tar Baby soon.
Everyone stay healthy.
Hi James, good to see you kicking out there.
I guess everyone in the Eagle Ford / Austin Chalk trend learned all there was to learn back in the days when this Forum was blowing and going.
Interesting to see how the various major properties have turned over via asset sales over the years. Some properties are on their 3th or 5th operator (of course, we all predicted this when the play was hot and active.
I still have ENVERUS (DrillingInfo) subscription for Texas and keep an eye on various counties plus keep an eye out for interesting corporate presentation news and well results.
What are the top 3 or 4 hot spots in the EF? it appears Gonzales county still has some activity between PV and EOG.
In my opinion, the ultimate hot spot in the Eagle Ford trend is Karnes County by far. I don't have the statistics (permits / drilling rigs / DUC's / completions) to back it up but this is my general observation.
One of the reasons for this degree of effort is tied to the fact that the Austin Chalk hot spot is coincident with the underlying Eagle Ford effort. And in my opinion, we have to look at the AC and EF as a "exploitation package" since the formation as so closely related.
Gonzales County continues to be a good spot for some operators (e.g. EOG) as to EF development (graveyard for AC for the most part). EOG's EOR efforts as to gas injection for more liquid recovery is focused in this county.
More and more drilling is being done in the more gas prone parts of the EF trend (again, along with some AC) in S Tx (Webb / Dimmitt / LaSalle et al Counties).
New operators like Verdun and Ensign have drilling programs ongoing / companies that have purchased EF assets have to drill them to justify these capital expenditures.
And CHK keeps chunking along in their S Tx and Burleson County core areas.
The fact that much of the good EF acreage is already HBP by existing production helps make new drilling not a necessity to hold acreage. Pure economics drive the need to drill and produce instead of holding acreage and keeping it from expiring.
Plus EF / AC drilling is competing with other US and international projects for their Operator's dollars (e.g. Just read this AM that Chevron is putting a Russian project at higher priority than their massive Permian Basin assets).
Life in the oil field continues!
Just my opinion here as always.
With Brent hitting $80 oil and $5 natural gas yesterday does anyone think we'll see increased activity in the EF or will it mostly be in the Permian Basin area?
High prices always help in encouraging more drilling - but the bigger issue for anywhere (Permian or Eagle Ford or anywhere else) is the situation with the acreage, the cash flow of the operator and their ability to spend capital on new wells.
I would estimate that almost all of the producing Eagle Ford acreage in Texas is in an HBP state - and therefore there is no need to drill to retain the acreage. So it can sit there undrilled as to infill wells / laterals as long as the original wells in the various units are producing.
Some of the earliest wells in EF trend have been dying out - thereby forcing the operators to drill new laterals to retain the acreage as the original wells die out.
Based on my personal experience, this is happening with Ensign in Karnes County where some of the early Pioneer EF wells are on their last legs and Ensign has drilled new (and much better wells) in these producing units to retain the acreage.
Higher prices may push some operators to drill more EF wells - even with the HBP conditions in place. I continue to see a lot of new permits in the EF /AC trend in the counties that I regularly monitor.
Same here Mark, it appears EOG is increasing drilling through allocations wells in Gonzales county. Some of the wells I monitor have over 12,000ft horizontal lengths. I'm also noticing the distance between well spacing is increasing but acreage per well appears to remain at 40 acres per well. This change in spacing leads me to think there will be additional wells drilled either deeper or shallower between these longer spaced wells.
Don't be surprised to see 15,000' laterals and even 20,000' laterals - those are becoming very common in the Permian and EOG has the skill set to do this. Only road blocks to longer laterals could be acreage related.
Also agree that lateral spacing has increased - possibly to minimize parent / child well interference.
Areas between laterals at one zone may be addressed by a "wine rack" approach with either deeper or shallower laterals as you have suggested.
To be honest, I haven't been tracking their or anyone else's ref-rac efforts recently. Devon not saying anything about it not a huge surprise - they have some much bigger fish to fry and public companies tend to not talk about things that won't move their needle with Wall Street.
I will take a look at some Devon wells to see if the re-frac effort is obvious from the production curves.
My curiosity about this led me to the ENVERUS site to see if I could find any Devon Re-Fracs.
In Dewitt Co, Devon has close to 1000 operated EF horizontals - and there is no way to search for "re-fracs".
However, I did stumble on two obvious re-fracs.
Both are some pretty strong results / note that these were done in 2018 and 2019.
To properly extract and evaluate Devon's re-frac efforts, one would have to go thru each well to see if they could ID the big production increase tied to a probable re frac.
The economic viability of the re-frac's is more difficult to ascertain. Although the increase in production is obvious and apparent, one would have to figure out the "additional new reserves" that are exposed via the re-frac and then determine if the costs of the re-frac vs these new reserves results in an economic set of results.
As typical in the oil field, no easy answers. Lots of subsurface variability and well results for a variety of reasons.