They had about 6-8 Frac Tanks on the pad, and about a week ago they removed them. I guess they did not need them since it’s all going through the pipeline.
No sense paying tank rentals if you don’t need them
Those are sand separators. You usually them on flowback. You just pumped a ‘big’ load of sand so you’re going to produce some back.
They’re pumping like 2500#/ft of lateral so something like 25 million pounds of sand per well.
You prefer it stays in the reserve but some always comes back.
Everything gotta be someplace.
Thanks - normally shouldn’t produce that much proppant in the post frac flowback but guessing this is not the case here
The oil sales price for the month is based on multiple factors. First is the calendar month average which is the average of daily settlement prices for the type of oil (eg light sweet crude), often as reported by Argus based on exchange price such as NYMEX-WTI. Second is the pricing difference between hubs. For example, in West Texas, the Midland-Cushing difference is the WTI Midland price at Permian Hub vs NYMEX WTI pricing hub in Cushing OK where much of oil is transported. There is also a WTI Houston price. Third is transportation factor because purchaser of oil in a remote or further location will pay less than oil next to the hub. These are main factors. Sales contracts are not publicly disclosed. It is very unlikely that EOG or any other large operator will provide their sales contracts without intervention by your attorney and signing a nondisclosure agreement. So far I see March prices running around $97-$99.
The price for April came in at $98.95 to be exact. I thought i had heard them say at one point it was priced as Louisiana sweet, which is a little higher than WTI. March came in at $89. I was also told, not be EOG, that the daily market price for oil during April and most of May was way higher than the WTI contracts for June or for now July. Some days as high at $20 over , but mostly around $7.00-$7.50. I guess mineral owners do not get that price, or the numbers for April would have been higher.
What surprises me is why it wasn’t installed when the original pipeline was done. Why are they opening a new trench it to install it? Seems like an expensive installation.
Mr_ML Talked with dozer operator at pecan pad he said his supervisor said county getting the limestone. I was told a wild back CR226 from FM 957 we’ll get fixed from all that truck traffic.
I’m thinking the pricing here a differential of WTI Houston. 55-57 degree oil is going to take a masive deduct to benchmark. Converesly, as Rock_Man, pointed out. The high gravity condensate lends itself to high BTU content. I can’t find gas gravity numbers but for those interested : Francis/Harwi in March: roughly 70% of revenue came from crude oil. Of the remaining 30% of revenue. Plant products accounted for 60% of the 30% and residual gas sales 40% of the 30%. So extremely high BTU content. Generally speaking, I’m calculating my effective rate in these wells at about $6 uplift to HH spot. If posted price on stub was $3/MCF the effective price is about $9.
I do have the API Gravity for the oil in April:
Blackshear 44
Parr 42
Reimers 38
Monster 35
Francis 54
Friends 54
Harwai 55
Mulimge 54
Bullard 41
Maddox 40
Holbrook 42
Chapman 41
The numbers do move up or down each month by 1-2 points.
The range of oil / condensate API values plus oil vs gas production numbers points to this play area have a widely ranging set of thermal maturity values.
That is, how the section was “cooked” over time so as to generate hydrocarbons.
More cooking = more gas / less liquids.
Similar to a refinery. But in the subsurface
Typically they install the lines in a separate trench. The black lines were put 2 to a trench.
Sort of hard to have many open trenches in a 100 foot easement.
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Monster Rock numbers are sure low. Wonder if there’s any chance of improvement long-term?
EOG has placed 6 new marker tall stakes indicating well locations and new pad on CR 183. These are about 1/4 mile east of 6 markers that have been on a tract north of CR 183, and these new markings are south of CR 183 close to the pipeline route.
From my maps this looks to be wells for only the 2 new units that go between the Maddox +3 pad and the Francis pad. The other 6 well markings (old) would be the additional 3 wells for Bullard and Maddox (south side). Each unit was initially planned a couple of years ago, to have 6 wells, we were told at the meeting, 3 coming off a north pad and 3 from a south pad…with the pads being shared by 3 other units…which would place 12 wells per pad when drilled out. Looks like so far, they are sticking to it…but we will see..
What always seemed strange is how the old 6 markings were going east/west, while all the other EOG well markings are always placed going north/south…including the new 6…since they drilled the horizontals in a NW/SE direction.
Anyway, we should get more clarification when RRC post the permits. FYI–rig is still on the CR 306 pad…looks like to be taking longer than planned.
306 pad is encountering lots of gas as evidence by this flare.
The original 6 i heard are being moved to the new stakes you see due to issues with the owner.
I think they are running north south due to the proximity of the pipeline.
Thanks LKranch for the info. and by further map investigation I do see that they can put a couple of these wells in both Bullard and Maddox. Maddox crosses CR 183 to the east of CR 189, so looks like a combo on 1 more Maddox and 1 more Bullard well and 2 each way for the new units based on what i am looking at …but we will see when they post permits very soon.
I knew CR 306 was going to be Extremely gassy…but probably not much oil…at least not as much as the Francis pad units…maybe half as much if we are that lucky.
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Do you know anything about the well CR312. I am a royalty owner in thing pool. The pool name is Worthington.
Just going to have to be patient.
Seems to be quite a bit of gas judging by the flares during drilling.
Next would be fracing and cleanout. Don’t count on anything for 7 to 8 months.
Any information or news about the Moravia area?
EOG still dealing with unleased tracts in their units… at least 2 of the units in the CR 306 pad…still unleased acreage. Problem here was that some of the acreage was not leased until about 6 months ago..people knew what Francis well had done, and people wanted more lease money. EOG had most of the northern end of these 4 units leased in 2023,2024, but a lot of the south and east was leased in late 2025.
I am still hearing this is true with some of the planned, but not as yet permitted units they have left. EOG is now paying some options as the 2023 leases not in production are coming due.
Redhawk leases had some in 2023 coming due for options but these are mainly in the James Lyons and Samuel Hanks surveys and most of these are in the Blackshear unit or Parr unit, so they are HBP…but still a couple of outliers. Rest of Redhawks leases come due first of the year 2027. I have not heard of any one getting options payments from Redhawk as yet…and I have friends and relatives in this mix…
Nothing at all being said about Redhawks plans. All I know for certain is that the Blackshear pad can only be used for additional Blackshear wells..Parr was a 1 well only deal on this pad…and the 2 southerly units that were suppose to come off this pad has been nixed by the land/mineral owner several months ago.