Have you heard any updates on the discussions between EOG and KEW to develop units north of Pecan?
Heard there was a âdealâ, but there are a lot of tracts that are only partially leased by KEWâŚmeaning a tract they leased does not have all mineral owners leased..so will take time to do soâŚplus they are not using all KEW leasesâŚonly ones within a planned unit.
Also the talk is not putting a unit above Monster rock, but shifting the unit 1 to the west, so one above Reimers and one to the west of that and then going up. This would be a 4 unit one pad situation, but not in line with the othersâŚ.again this is under discussionâŚdepending on results, but they had an extremely thinning of the upper EF in Monster as they went east.
Have to stay tuned for resultsâŚâŚand the economics will be a big part of the decisions going forward in this neck of the woodsâŚgoing into Fayette countyâŚ
As is the case in plays like this, it is all about the rocks!
Thanks, interesting info. I am going to be keeping my eye on this seeing is this certainly impacts my familyâs acreage!
When you say âaboveâ Monster Rock are you referencing to the North of Monster Rock? What about toward the south of Monster Rock? Is that one still planned in line with Monster?
Does anyone have any information on the pad for Kainer B unit? Seems like itâs pretty deeply on private property. Permit is still on hold
Crud. This appears to be a reply to an unrelated thread - unintended.
Yes, a pad/unit north of Monster is in questionâŚactually a pad/unit anywhere north of Pecan pad âwasâ in question because EOG did not have all the leases.
The initial unit maps from early 2024 are the ones being permitted almost exactly as planned. However, they were all still on hold until testing. After Francis well EOG âprovedâ up their acreage north to the Lavaca river. Blackshear results âgreen litâ the 2 units under it, and the 4 units above it. (future CR240/FM 957 pad)
Pecan pad looked promisingâŚ..and at this time there are still plans to do the south 2 units from Pecan Farm pad, and another 4 units below that (future CR229/CR263 pad).
Although some talk of westerly movement, mainly on any units above/north of Pecan farm.
There was talk of moving some of the units west just a smidge above Blackshear, but that has not been mentioned lately. If you look at how the units are designed, the 4 wells on one pad for 4 units goes from Francis pad toward the north,and plans are to make a pad at EVERY 4 corner mark eventually to drill out the units having 4-6 wells each unit. So every pad would have 8-12 wells on it when done.
So when a pad site for the 4 units are permitted, where they meet again north and south 4 corners with the next 2 units, the pad site is already planned and approved by surface ownerâŚeven though this would not be done/drilled/permitted until 2027 or later, as they try to hold all leases with one well before option payments dueâŚ.
I was given a map by Redhawk when I signed my lease in July â24. Admittedly itâs a one pager showing only âmyâ unit but you can see from the margins that apparently they laid out a unit grid over the entire area regardless of whoâs leased to who. In fact if you get out the magnifying glass youâll see that each tract is already numbered within each unit (I have a number).
Also for âmyâ unit at least, the directional orientation (slope/slant?) looks to be exactly that of the pecan pad. This doesnât appear to be true for Blackshear/Parr though. Theyâre too E-W.
So to your point, it would probably save a large amount of staff work if they just shifted any units above the Pecan Farm âupâ one unit to the NW on their grid if they decide to do that.
As an aside, Iâve started a bad weather project to see whoâs leased to who and have put those on a color coded CAD map. Iâm far from finished but EGAD! What a patchwork of leases between Redhawk/KEW/Acaval. Hoping that they can get it all worked out.
Uh ohâŚ..Parr well results are outâŚ..
523 bopd in october based on 10/13 start of production
2.3 million cu/ft nat gas/day all this based on 18 production days
However⌠the oil numbers have about a 7 day lag, told to me by EOG
so that makes Parr at 856 bopd (not boepd, but bopd)
What Blackshear had:
1690 bopd and 4.7 million cu/ft nat gas/day
This puts Parr well at half of Blackshear production and now Parr has an 18 month payoff instead of Blackshears 7.5 month.
That is why EOG has been in discussion (they saw daily numbers) to move westerly a tad bitâŚbut they still wanted to test north (monsterâŚ.) and from what I heard as far as drilling issues and horizontal issuesâŚMonster will probably be pretty dismal in comparison to the southern wells.
Again, Iâve heard the Andrew unit south of Parr and all others south are green lit as well as are the 4 units above Parr and Blackshear. But I would not be surprised if the units north of Blackshear pad changeâŚ.gotta make some callsâŚ.
Thanks for posting this info - definitely not what everyone wants to see.
Lots of moving parts here as to reasons for post frac flowback variability - including landing zone, staying in target interval, frac approach and details. And most importantly, the variability of the target interval and associated stimulated rock volume (fracâd interval) as to key reservoir characteristics.
Even with the better early production, the decline profile will come into play as to the bottom line economics of this area
Another thing to keep in mind is that this is early in the flowback. Also, with EOG in acreage acquisition mode, they may try to downplay the results of these wells to minimize competition and reduce acquisition costs.
Pecan pad looking good started last Thursday cranking it on slowly but it looked not to plan. Friday better heard a few pops but no flame. Water trucks been running none stop. Iam sure gas been going some were was about 6 white trucks at Philips pipe line Thursday morning. Some body smarter than me can tell what exactly that steamer does.
My Guy is unsure but thinks itâs a cooler (radiator) to cool down hot flowback water because SWD plumbing is poly to keep it from corroding and so canât be very hot. Not to mention hauling it to the nearest SWD well.
Donât bet the farm on it though.
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Post frac flow back may be taking longer to see gas break through - common occurrence.
The steam you are seeing probably tied to running the flow back fluids thru âcooling systemâ to being down temps before running fluid thru separators (where higher temps may cause damage)
Based on log header info from deep wells in the trend, bottom hole / reservoir temperatures here should be in the 250 degree F or higher ranges
I think your comments are dead on
So I have some news. I am in a lease with EOG in Lavaca county, betweem CR 194 and CR 195 just north of FM340. I heard 10 days ago that drilling will begin early next year and there is a 7 acre pad for four wells. I am new to this and inherited the lease just after it began in 2024. I am unsure if this one is pooled and if so how big it is. Can anyone give me insight on what to expect?
All depends on what your lease says. The lease you inherited may have a pooling consent requirement or it may not. It ultimately doesnât change anything, just if they have to notify you first before pooling you.
If you donât have that requirement in your lease, then you could do some digging on the RRC website when their permit gets posted with the unit (I can help with that if needed). Otherwise, your lease will be pooled into the unit and when they start to produce, youâll receive a division order to execute which shows you your percentage of the unit, etc.
These 4 units have all been permitted alreadyâŚI posted this over a week ago I believeâŚ.Kenobi, Alfaro, Bruhn, Rawlins are the units nameâŚ.âŚ
You might not be listed by your name on the mineral owner section if you tract has multiple mineral ownersâŚit would just have one persons name and then âEt ALâ meaning âand others.â
You will just have to search your tract to see if it is in the unitâŚ..if you have the tract address I could look it up, or you can go to the Railroad Commission site and research.
Division orders might not come out until 1 month or so after production beginsâŚwhich will not happen until around mid MarchâŚthey have to drill 4 wells and frack 4 wells before they start flowback/productionâŚ.
I just heard that poly and other sensitive equipment is only good up to about 180*. So at 250ish thatâs way too hot.
General question: Whatâs a Cliff Notes explanation for the difference in Bottom Hole Temperatures (BHT) from one area to another? I could understand if itâs around Yellowstone (the park not the tv show) but north Lavaca County does not follow.