Rig is gone and all that shows from the side road is a small two tank production battery. No flare.
The adjoining land owner says all he's heard is they made a gas well and he thinks are working on a pipeline connection. It looks like Kinder Morgan has a gas line nearby but there could be a reason they can't tie-in there. Someone with access to DI might be able to confirm if it's been fracked but expect it will be a long time before EOG files a completion report.
EOG (or any stealth operator) has yet to file anything on FracFocus.org site as to stimulation details. Agree it will be a LONG time before EOG files anything with the state on this.
New directional survey covering the lateral hasn't been filed either.
Would DI usually show if it has been fracked?
Here's what it looks like now
Drilling Info shows nothing - latest info is the original May 2017 filing after the vertical well was at TD of 15,400'. Directional survey for vertical well is only info on Tx RRC site.
DI will not indicate if well has been frac'd - this is only included in DI if the frac info is including in any filed completion report.
There is a 10" Phillips 66 gas line in the same ROW as the Kinder Morgan products line - located about 2400' due north of the surface location for Tonkowa (but it will take longer trenching to get to this line depending on where tap is and how line needs to work around the creek in this area).
Photo looks like a typical EOG location (including color of equipment). Dual 400 bbls tanks (one of water and one for condensate?). Looks like a dehydrator unit and possibly a separator to the left of the tanks. Plus tower for info transmission / safety monitoring.
Small on site tankage would tend to point to some pretty dry gas (or gas and associated NGL's going via pipeline to processing plant). Regardless, not a lot of liquids being separated and stored on location.
I figure well is up and flowing gas to sales as I look at this. Or it will be flowing to sales soon.
Thanks Rock Man. No signs of any pipeline work when I was through there last weekend although RRC's map shows those existing lines running close to the side road I took that picture from.
RRC shows that 10" Phillips line being propane (NGL) and Kinder Morgan's being a 24" natural gas line that is part of their Hill Country (Rancho) system. Maybe it's a trunk line that EOG can't access directly?
I liked hearing your thoughts on what EOG's production setup indicates about the Tonwoka. What do you think about Geosouthern and Wildhorse always installing big tank batteries, at least five large crude tanks, on every new AC well they've completed in Washington County but then reporting little or no liquids production from several of them? They aren't in EOG's class as operators but I can't understand them building those big setups before they know what the well can do. They're both projecting to drill multiple wells from some of those locations so maybe what they've installed was designed for their ultimate combined flow? Appreciate hearing if you have other ideas.
As to tanks on location issue, thinking that EOG is making very little liquids via the separator and is taking gas (and associated NGL's) to processing plant.
Geosouthern and Wildhorse may be having more liquids produced on location that need storage than what EOG is seeing (note that EOG is much deeper and probably more gassy and less liquid rich than both Geosouthern and Wildhorse).
Geosouthern and Wildhorse could also be setting up tankage for other wells - tanks are relatively inexpensive and can easily be moved off original pad to other locations.
Also, part of the larger tank batteries could be tied to need for more water storage.
Appreciate your ideas. I'm sure you are right about some rich gas being processed downstream. Still amazed though by wells like Geosouthern's Winkelmann where the completion report showed 17.4 MMCF/D of gas but just a blank space where they were supposed to report crude or condensate volume after they had rushed to install five big crude tanks plus additional water tanks and separators there.
I thought GS must be keeping the true numbers under cover but for the first three months they've reported gas averaging 13-14 million/day to RRC for that well but still showed a blank space every month for any liquids.
Winkelmann completion report showing 0.637 gas gravity for both mixture and "dry" gas - since actual dry (no liquids / NGL's) gas is around 0.59 gravity, there is some liquid associated with this gas stream.
Tx RRC report on production shows a "2: disposition code - so gas is going to gas pipeline and not a processing plant (code 3). Gas line may be taking the full well stream of gas (let's assume a 1050 Btu value) and giving GS a percentage increase in gas price for higher Btu.
I cannot comment on why GS put so much tankage on location - but tanks can be removed and taken elsewhere. Figure that there may be some condensate in those tanks (is there a separator on location?) but not enough to call in trucks to transport out loads as of yet.
Energy Transfer taking all the gas as per Tx RRC filings. Shell Trading listed as gatherer for liquids from wellsite.
Was hoping to find a gas analysis on Tx RRC but nothing posted.
Appreciate those details. I'd been wondering about gravity of dry gas and didn't realize the distinction on disposition codes. Also hadn't thought about the fact a little condensate might be sitting in those tanks. Thanks
Would anyone know if the Geosouthern or EOG wells are profitable in those locations, by getting mostly dry gas and very little liquid ? Is that why we have not seen a new permit filed in fayette county in almost 5 months ?
I have heard through the "rumor mill" that EOG is looking to test their acreage in NE Lavaca county very soon....but the 2 people I heard this from have no links to EOG that I know of.....
Without knowing GS or EOG's well costs and production costs, it is next to impossible to take a stab at economics - it is well beyond multi variable calculus!
I believe it all comes down to rate and production decline. Assuming a gas well (no significant liquids) is making an average of 10 Million CF gas per day (IP in the mid teens / decline to around 7.5 Million after 12 months). Using $2.75 per MCF and 75% NRI to operator, that is around $620,000 per month (pre operating expenses).
Add in some condensate and/or NGL's and things get juicier. Using 50 bbls NGL per MMCF of gas and $20 per bbl NGL (low estimate) with 75% NRI, you get another $225,000 per month in pre op expense revenue.
$845,000 per month total for gas and NGL's in this scenario.
The small print at the bottom may be hard to read but that graph from page 17 of their presentation says Wildhorse projects 34% IRR (possibly improving to 39%) based on the results of their first three Washington County wells. They've already fracked one more and say possibly 7 more are programed this year.
As you probably know EOG recently added the lateral leg on the Tonkawa the 15000' research well they drilled down where Colorado, Fayette, Austin and Washington Co. come together. People down there say they made a gas well but no indications how strong. Which way EOG now decides to go may be the big story.
Geosouthern being private isn't talking but the fact they are drilling ahead on 11 active Washington Co. permits and moving dirt on several more multi-well pads in that same trend area seems to say they are happy with the three big (10 - 14 MMCF/D) gas wells they've completed recently.
30+ IRR nothing to sneeze at. What does fine print say about assumed prices? I think I see it but cannot make it out.
Note their NGL / gas / Condensate pie chart - some reasonable liquids (about 33% total)
Note 2 at the bottom of that chart says "IRR sensitivities based on consensus pricing as of 3/1/18, $60/$3.06 for 2018, $60/$3.05 for 2019, $62.00/$3.13 for 2020, $61.75/$3.19 for 2021, $57.00/$3.22 for 2022 and thereafter for WTI and Henry Hub, respectively."
Since Wildhorse like a lot of others always talks in terms of BOE's I'm wondering how NGL's were priced in their economics.
Hmm, their gas price strip is high to real world right now. I bet that NGL pricing is buried somewhere in the appendix at the end of their presentation
I am thinking that maybe their gas strip price is including a btu adjustment for the ngl content of the gas since there is no mention of NGL pricing.
Possible but surprised if they did this since they are showing a three product flow in their pie chart.
The gas strip they are showing would be about an 1100 Btu gas if I am looking at it correctly
Hello. Just checking in. Haven't seen much activity on this site lately. Have you heard any more Mr. ML on EOG and Lavaca County North part lately? Any bites anywhere on any companies drilling North of Hallettsville? Everyone has been so quiet on this site lately so making sure I'm just not getting the emails of conversations or if it's just been quiet. Thanks.
EOG has not reported any production to Tx RRC as of the latest possible month (February) / this goes for either active or pending status.
Any observations in the field? Perhaps tankers taking fluids (oil / condensate or water) off of location?
As to other companies, Geosouthern has permitted SWD well near their Ammansville operations - positive sign that they are looking to spend this sort of $$$ for this area.
