Some posters on this site have referenced various production numbers tied to truckloads of oil being taken off of location as well as reports of gas rates, but no completion reports (and IP data) have yet to be filed with the Tx RRC. And no production info (even in the Pending Category) has been posted on the Tx RRC site as of the latest date (October 2025).
In my opinion, until we see some actual production figures, there is no sense guessing at estimates of how these wells may perform.
And once we start seeing monthly production and daily rates, the key to the long term economics for these wells will be the production decline profile. These types of wells (i.e horizontal unconventional reservoir wells) will have a rapid production decline profile - the question is how rapid.
Stable production is NOT The norm for these types of wells.
An example of production decline is a Hz well that is making - in Month 12 - about 25% of the production that occurred in the 1st full month of production.
Thank you for your reply. If you assume a well in month 12 is making 25% of the Month 1 production, would a reasonable assumption be the well economic limit will be reached at the end of 2 to 3 years of production?
BTW, what is the closest well ( to the SW I assume) with actual production that I can look at? I also assume production will decrease , for the EF, as you go northeast. The big issue the current wells will determine, is , how much. Correct?
Thank you all for your very detailed surveillance of the activity in this area.
I am not surprised EOG has not filed production numbers yet with the Railroad CommissionâŚthey seem to be always trying to hide somethingâŚlike we donât know they ARE RedhawkâŚ..even though not one mention of Redhawk in any quarterly report and this area is not even indicated on the maps they provide in their presentations.
I for one get my ânumbersâ from the Texas Comptroller of Public Accounts, and from the information received with my monthly checks (I refuse to get direct deposit, so they have to send me all the info), just double checkingâmaking sure they matchââŚkeeping them honest. I am lucky enough to have minerals scattered over the central and northern portions of Lavaca countyâŚnot a whole lot on one tractâŚjust a lot of little onesâŚ.and maybe some pad site locations.
So, any numbers I have sent out on Francis or Blackshear are solid.
No one has ever talked about EURâs for these EOG wells that I overheard. All we can do is see what is out there. The Finn units below Shiner were not good for EOGâŚthey moved to Francis and it was hugeâŚBlackshear came in bigger than they thought, but not as good as the well logs indicated. so, if you look at that data you can see that so far the oil and nat gas has higher production at the southern end (Francis) than what is known so far in the northern end (Blackshear). So, for EOG this âprovedâ up the area between Blackshear and Francis padsâthat is why they are drilling it to hold as we speak.
Francis should have payback in about 6 months and Blackshear 7.5 monthsâŚrevenue minus royalty minus all expenses to date. as long as you donât count shutdown times for drilling adjacent wells. The payback in the Eagleford area is one of the best EOG has among all their plays.
Also at this time the decline rate is equal to, or actually slightly better, than the average EF well rate of declineâŚ.but that is just with the months we have so farâŚ
We will need the production numbers of the Pecan pad wells to see how this area of the Austin chalk trend delivers. i can tell you that they expected less oil and more gas than Blackshear or ParrâŚbut that is their guess.
You have to submit an âas-drilledâ plat that shows where the wellbore ended up etc. The only change is typically if the toe of the lateral didnât get completed or gets trashed, etc. But generally the permitted and as-drilled end up the same for the most part.
From what Iâve been told itâs much more preferable to began ASAP. You basically rig down frac, drill out the plugs with coiled tubing, then plumb it into the flowback iron and get started.
The production in these types of wells will flatten out once they get a certain rate - and then flatten out for the next several years.
One can look at some nearby Hz production to try to get an example, but it is my opinion that this area / these Hz wells are targeting a Lower Austin Chalk section and not the Eagle Ford (which is probably very thin in this area). It is therefore difficult to find nearby analogs for laterals drilled in this section.
I did some searching and found a key 1982 vertical well that sits in the middle of this Hz drilling trend. This 13,000â well TDâd well below the Austin Chalk / Eagle Ford section.
As I had posted in earlier tonight, the Eagle Ford section here is very thin - only about 55-60â of apparently organic rich unconventional section. There is a 25â thick Maness Shale section that sits below the Eagle Ford and above the Buda Lime - the Maness is not considered to be a prospective unconventional reservoir due to its high clay content and ductility.
The Lower Austin Chalk in this well (about 70-75â thick) looks very attractive based on log response.
I would be assuming that EOG / Red Hawk are laying their laterals either in the uppermost part of the Eagle Ford just below the Austin Chalk or in the lower part of the Lower Austin Chalk section. And then depending on the frac to create a stimulated rock volume (SRV) that includes the Lower Austin Chalk and Upper Eagle Ford section.
Basically, mechanically commingling the Lower Austin Chalk and Upper Eagle Ford via the frac stimulation.
This same landing zone and SRV approach has been used by other operators in other parts of the Eagle Ford / Austin Chalk trend - most notably by Penn Virginia, Devon and Conoco Phillips
I have been wondering why EOG/Redhawk does not list the Austin Chalk in their permit filings with the Railroad Commission. The wells in our area in Lavaca county do not have Austin chalk mentioned. In Gonzales county, they were permitting the same way as Lavaca county, but then I saw that they had to amend their W-1 to state Austin Chalk as one of their fields. This has happened in a number of the Gonzales county permits recently, with remarks that the horizontal is going in and out of the EF and AC fieldsâŚjust one example is the Badlands F unit. If they were doing the same thing in the Lavaca wells, I would guess they would have to do the same ? Unless they are only staying in the upper EF ?
Also as far as an operator maintaining the âleaseâ after the expiration, I thought this was the lowest depth that the operator is getting oil/gas fromâŚ.or is it anywhere in the field they had on their permit ?
Over a year ago when we were approached about a potential pad site, I did ask them if they were going into the lower EF, and they said â not right nowââŚ.but will these 13,000-14,000 depth wells hold the lower EF that in this area is about 14,500-16,500 ?
Yesterday went by the well that Neighbors 1209 drilled to see all the Frack equipment that was at the pecan pad.
Right down the road neighbors rig 1209 had one big gas flare already and they were laying a pipeline to the pad that is getting fracked.
So this is an interesting case. Operators have to choose the âfieldâ in which they want to permit a well(s) and whichever field they choose will dictate the rules that the RRC has set for well spacing/lease line spacing etc. In many cases, operators will choose a field where there is another well that is landed in the same interval, but in other cases operators may permit the well as a âWildcatâ and then when they complete the well, file an amended permit indicating which field the well is producing from.
There are a bunch of rules that vary by field, as noted above, which can also dictate how much you can produce from X amount of acreage etc etc. It really isnât overly clear and always created an issue (in my past experience) when âpickingâ a field to permit the well in. One would think there is clear guidelines or maps that show the field boundaries, etc. but that doesnât exist.
Not sure about the SW, but the closest well to the SE has an OIL well producing for several years in this area. The Debord well, 28531850, 14â300 TD, Austin Chalk-2, 1H. Off of LCR 217.
Depths HBP by production depend on the lease - if there is no Pugh Clause / depth severance, all depths below the producing interval are HBP.
If there is a Pugh Clause, depths below the producing interval based on a certain footage below that zone are released once lease term date takes place.
Normally, this depth below producing interval is 200â.
Key to Pugh Clause is the wording in the various leases
If comparing to this Debord AC well, first determine if it was a fracâd lateral or just a natural completion tied to natural fractures (perhaps with some acid stimulation).
These completions are totally different from what is happening today with the EOG / Red Hawk laterals
Thanks for responding to this, I meant to comment. Totally depends on the lease form. It isnât only depths (above and below are ideal) that you want released if an operator doesnât drill, but also the amount of acreage they can hold with a single well.
Your research is dead on - looks like operator here drilled two open hole laterals in the Austin Chalk trying to find natural fractures (and then abandoned those deep laterals).
I have a general question. When I look at the W-1 thereâs a field called âTotal Depthâ. But then when I look at the plat no matter how I math it, I canât reconcile those figures (FTP, LTP, et al) to Total Depth. What exactly does Total Depth mean on the W-1? Thanks.
Total depth is the better known as âTVDâ meaning true vertical depth. How âdeepâ the well is landed. So, Reimers unit landed the lateral at ~13,000â and then drilled 10,102â horizontally.
