Right Todd.
But it looks to me like there are 2 sets of Pyle wells.
5 Pyle 5-25-36XHW wells for 25-7-6, which run south from 25 to 36.
And 4 Pyle 4-36-25XHW for 25-7-6, which run north from 36 to 25.
Is that the way you see it, Todd?
Thanks in advance.
Joe These rigs are sitting on the very North edge of Sec 20 & 21 and Drilling North. This means our Sec 20 & 21 are not getting any of the perforations, therefore no money for us.
Yep. Here’s the survey.
Sec. 17 gets 40%, Sec. 8 gets 40%, and Sec. 5 gets 20%
All Section 20 gets is the SH and no production.
CLR just proposed additional 6 Springer wells for sec 11 6N-6W . Includes sections above and below also. CD 201806170
Looks like Continental is already starting on Row 3, with 3 new wells proposed for 36-7-6/1-6-6 in the Springer formation.
Rick, LOL! I have the same problem in my section. I know most well are drilled south to north and I thought you were inferring that CLR was drilling north to south. I have a good producing well drilled by Apache which is drilled north to south and was going to assure you successful well can be drilled north to south. But I get it now, they are using your section to drill into another section.
If those sections are considered ‘held by production’ that doesn’t seem very fair at all.
That’s not going to happen, John, because there is no production from the SH section.
“Held by production” is a provision in an oil or natural gas property lease that allows the lessee, generally an energy company, to continue drilling activities on the property as long as it is economically producing a minimum amount of oil or gas.
But those sections with only 10% of production coming from the surface hole section would be “held by production.”
So I guess the rest of the section would be off limits to any new wells from any oil company other than the SH producer.
If you have perforations from a well in your section and it is producing, you are held by production.
If you just have a surface location (SL) and they do the vertical portion of the hole in your section and make the turn, but do not have perforations until the next section, then you are not held by production. (unless you already have a well in your section.) It is all about the producing perfs.
Hi Debra: This section is a real crazy one, as they all are going to be. So far, I believe, not to be confused with what eventually happens, is there will be 7 wells in the “PYLE” unit consisting of Sections 25 & 36. Some of these are going to be Woodford wells & some quite possible Hunton wells. All will be drilled within Sections 25 & 36.You should have received revenue from Continental recently (last week) for the Pyle 1-36-25XH well.
So far there are 4 Williams wells that will be partially in Section 25, but mostly in Sec. 24 & 13.
Now there are plans for 4 wells named Hart, that will be to test the Springer. Eventually, there will be several wells, most likely 4, to test the Sycamore.
I am in another unit close to here that there are 21 wells planned, various zones.
Stay tuned.
Todd M. Baker
Will do, Todd.
And thanks!
Anybody heard of any court filings on Sec 20 or 21-7N-6W. I try to check every week but dont know if I have missed it or not
Haven’t seen any yet, Rick_S. Unless I have over-looked it…I have a friend that owns in 20. So I try to look.
Hottest in America!
With breakeven points averaging around $35 a barrel and initial production rates that parallel the vaunted Permian and Eagle Ford basins, the SCOOP/STACK shale basins in Oklahoma are arguably the hottest oil plays in the U.S. today.
Thinking 23 & 22 7n 6w will be next in Row 2 before 20 & 21 …Prob because my lease is in 23 7 6 LOL
This application for the Pyle 2-25-36XHM in 25-7-6 says on page 2, it’s “moving toward” Sec. 23-7-6 .
You’re making progress, George!
Thanks Debra for the info! They already have a pad laid in Section 5-6N-6W, just waiting for them to stand it up and also dig the rathole. This well may be coming sooner rather than later.
They’re are drilling 18,000 foot laterals in the Marcellus, covering 3 1/2 sections.
Maybe coming to Scoop pretty soon.
I’d like to ask M Barnes if she thinks this is good or bad for royalty owners.
Thanks in advance, M.
“By spending another day or two we could essentially double the lateral footage, which was the equivalent of drilling a second well in two days. In 2013, a 27% increase in average lateral length reduced our costs per lateral ft by 24%.”………
, the logic behind drilling an 18,000 ft or longer lateral length well is simple math. When you consider that back in 2012 the drilling of a 3,000 ft lateral length well was costing nearly $2 million per well, and in 2018 you can drill an 18,000 ft lateral length for well under $3 million, then it becomes obvious that you’ve experienced a major game changer.”
If they can get the technology right and the extra footage results in a proportional increase in production, then it can save lots of costs from drilling extra vertical portions of holes, less surface acreage used, etc. Lots of fluids and frac sand though which is $$. The long length is possible. I know of a team in the Gulf of Mexico that drilled a really long directional well that set a record in that day and age was much longer than this. Made a lot of money. If the formula for royalties stays the same, then I think it would be fair at least for the full sections. The half section guys won’t be too thrilled that they are being held with a small percentage of perfs.
ladies it is already happening is scoop: http://occpermit.com/WellBrowse/Webforms/WellInformation.aspx?ID=594757
not 18,000’ but 15,000’ or 3 sections. They have the technology both in drilling and in completion. Usually it is a land issue that keep it from happening in more “mature” areas. I track the production on this well it is a VERY good well.
