SBC, I’ll check this section when I get into work to see if Devon has already drilled it up, or if there is room for more development. $250k per point isn’t a bad offer when that many BCF have already been produced out of the section. But before I speak out of them I’ll go check.
SBC,
My mental map was off by a few miles.
Section 8 is 4 miles north of the core of the Cana Woodford, so it’s not all drilled up yet. There has been one Woodford well drilled already, the George 1-8H, and it’s not great. But it was also completed with older frac technology, so that explains a lot of it.
$250k is still not a bad offer, though, especially if you are getting hammered on the realized gas price. These wells are extremely gassy, and it is rich (high BTU) gas, which should make a lot of liquids, so it should be commanding a premium to NYMEX. Can you provide any details on the deductions clause in the base lease from which your ORRI derives? It would be helpful to know how bad it really is. Using rough math and $50 oil/$3 gas realized prices, $250k is over 40 years of current cash flow per 1% ORRI. That obviously won’t work, so they are in it for the Multi Unit well Devon is trying hard to get approved from 5 down into 8. That well will be a Meramec. There are precious few new Meramec wells within a 3-5 mile radius of you, the best Meramec is a little bit north of you in 15N and 16N.
There is a good chance that if you have a 1% ORRI, $250k would be worth more than your share of all the money the Devon well will ever make. I’d consider selling part of it. You could always keep some for the future or the grandkids, and take some chips off the table now while there is that kind of offer floating around.
My $0.02
Thanks Justin. I don’t know about the original lease. It was a long time ago when the Hubbard well was drilled and I was at Slawson but the marketing deducts are running 25% of gross. Yes, the gas price is premium at $3.83/mcg. Yes, the Rebellion George 1-8H is the one that I recently started getting paid on and you are correct it doesn’t appear to be very strong which is why I thought the offer was pretty interesting. But when M Barnes was talking 47 BCF and 270K BO for Woodford and another 17 BCF in the Mississippian over in 17 of 11N - 6W I began to wonder. I still get a few dollars a month on some other old wells operated by Devon and Range in 8 if 14N - 9W so I don’t know who is ending up operating any other future horizontals in 8 but I haven’t seen and increased density apps.
I have 1 net mineral acre in Canadian County I would like to lease. Does anyone have an idea of who is leasing in this area right now? Sec 13, T-12-N, R-5-W
anthing going on in section 32 canadian county.
James, I was mistaken, the court application I received was covering sections 30 and 31. Not 32
John, it sounds like those are company specific requirements. Are you looking to receive an evaluation on your minerals?
How much acreage is needed to drill a horizontal well? How difficult is it convert a vertical well to horizontal and how much space is required and can it be done in a housing addition?
Horizontal wells are usually spaced at 640 acres which is a section. Some wells cover two sections in their horizontal length.
Most vertical wells cannot be converted to a horizontal because their casing design is too old to accommodate the additional down hole machinery needed to drill the turn and then the later part of the hole. Some are, not many.
Surface location can be in a different section to drill down the vertical part and then turn at depth and drill the horizontal out under an area that would have all sorts of things on the surface, ponds, golf courses, houses, etc.
Originally, yes. Then if the reservoir horizon can handle more production, the operator will get permission from the Oklahoma Corporation Commission to drill more. Some sections may have up to 20 wells in the future. Those will probably be in Blaine. Some Canadian County sections have eight or nine already. Usually the surface location will host two-three wells-more efficient use of space. Go to the Continental Resources, Marathon, Newfield, Devon and Cimarex websites and look at their investor relations slide shows. They have some very nice diagrams.
MB, thanks. Re “Horizontal wells are usually spaced at 640 acres…” - does that mean there is no more than one start-hole for a horizontal well in a given section ?
Great, thanks.
Devon Rhino 8_5, 14N-9W, multi section horizontal was supposedly spudded on 7/22 and would presumably be in completion stages by now. Does anyone have any information on how this well is looking?
Justin,
I agree with you. I did not take a hard look at the recovery factors, just the ballpark “how many wells”. The best recovery I have seen in the Woodford is about 4-7%, so even if they could get to 10% that would be great with today’s technologies. The Meramec is a bit better from a poro/perm perspective, but it will probably not go to 35%. That is closer to a conventional reservoir typical recoveries onshore. Offshore overpressured zones are a different ballgame.
However, the OK state legislature has approved long reach horzizontal wells into conventional reservoirs as well as shale reservoirs, so that leaves some upside in the recovery factors for more conventional reservoirs. Horizontals can do a lot of good there if the zones are not already depleted.
If mineral owners want a more accurate prediction of what their minerals are worth, they would probably have to hire an experienced reservoir engineer to give them a better answer than the “ballpark” ones. Our family does that about every five years for our entire portfolio so we know where we stand.
David Evans, you say your minerals are near the old Downtown Airpark? That is in 11N-3W, in the heart of a very densely developed and populated area. I wouldn’t expect anything to be done in this area…maybe ever.
Other thing you want to be sure about is the lease language for “deducts.” These companies are killing landowners whenever they can by deducting enormous amounts for gas marketing, transportation, compression and whatever other costs they can get away with. I have royalty associated with some very old leases and the deducts have been over 1/3 of product sales revenue in many cases.
I guess we will be pleasantly surprised in a couple three months or not…Section 32, Township 11, West, Range 5, Canadian County…
Stacy, all four years total, not yearly, at estimated oil price of $48 and gas at $3.00.
Friend me and I can share the spreadsheet with you.
M Barnes, one thought on Cimarex’s increased density reservoir engineering exhibits you were discussing in response to Jon’s question on 17-11N-6W:
When they ran the volumetrics to estimate the recoverable oil and gas on future Woodford and Miss wells, Cimarex used the same recovery factor…35%. I saw the Mississippian calcs first, and thought “hmm…35% seems awful optimistic for a rock with such low perm”. But then I saw they used the same 35% for the Woodford also, a reservoir with micro- and nano-darcy perm! There is no possible way that those to reservoirs have the same recovery factor, and neither of them will be anywhere close to 35%. If it were, we wouldn’t need horizontal wells in the first place. The reason we need horizontal wells is because lower quality reservoirs are so tight that you can only drain a tiny, tiny fraction of the reservoir (probably <1%) with a vertical well. Even with a huge completion on a horizontal well I seriously, seriously doubt the actual recoveries ever exceed 10%. That is an insanely optimistic estimate on Cimarex’s part – done, no doubt, to help convince the commission that they need so many wells per section.
All that to say, 11N-6W is really good rock, i’m not denying that or trying to contradict your point. I’m just wanting to reality check the “pie-in-the-sky” calculations put forth in these exhibits…it makes the reservoir engineer in me freak out a little bit. If I were a mineral owner, I’d want a realistic expectation of what my minerals could actually produce someday.
So what is a realistic expectation a what a return one may get on a well being drilled with only 1 acre mineral right of 640. With 1/4 royalties and a 3 year lease? active wells producing? They are drilling about 9000+ down and 14000 horizontal, and how long will it produce what can I expect if anyone knows an estimate?