I mean how are those amounts arrived at. I don't understand whether they are a guesstimate or are they actual test amounts from a real test of the well. Are they an actual IP of the well? No one has really explained how those amounts are arrived at.
Im not sure, but the estimated potential has turned out to be the IP on the last several wells. The IP is turned into the state by the operator (whether it's true or not).
Supposedly the allowable is based on what type & depth well it is.
I think you are right but I was hoping that someone had direct information where those figures come from and how they are derived.
Can you tell me where is Weyerhaeuser 73H so I can look it up on Google Maps?
A neighbor told me the Girl Scout camp (roughly 400 acres) located off of hwy 61 near hwy 66 signed two separate leases; one for TMS and one for AC. Is there any truth to this, and if so is there anything significant about this particular location?
I don't know about this.
I think you may be referring to Camp Marydale, http://www.gsle.org/camping/marydale.asp.
I hope your information is correct.
They got some very good advice. This will put them in both plays. I hope your info is correct.
Would you mind explaining how signing two leases is significant and what is the implication for those who have both formations but just signed one lease.
If a person signs one lease and there is more than one productive formation under the property then the one lease will govern the drilling and production from both or all formations. In that case all formations, above and below, will be HBP from any one of the formations. On the other hand, if there are two or more separate leases on the property then each lease can govern the drilling and production from each formation or zone. In my case I've written an addendum that allows the drilling and exploration of one specific formation per lease. One thing that you need to be aware of is that most leases governing a specific or in some cases a lease with a depth clause extend the lease by 100 ft. below the formation drilled or 100 ft below the deepest depth drilled (depth pugh clause). In the case of the Eagle Ford there is no 100 ft. buffer zone below the Austin Chalk and in the Case of the TMS there is no 100 ft. buffer zone between it and the Tusc sands. So I feel that I have to be careful when I put some of the standard phrases that most of these lease addendum use. As far as I'm concerned anyone drilling a well now with the technology we have does not need the 100ft. buffer.
Enjoyed you post. First I think that we all have been "dumbed" to some extent in the past by the industry. And Yes, I think the operative phrase here is "Live 'n' learn". I am so thankful that Keith has put this site up and we are able to bat things around about the industry and how we need to interact with it as mineral owners.
Now about the Lease Language. I agree with everything you said. My lease actually defines the formation that the lease covers as a formation that was penetrated in a well in the past in the area. I'm primarily referencing the drilling of the Tusc. wells in the 70's and 80's. I think the formations that show in those wells are well defined and there should not be a problem with the industry or a court acknowledging what level, depth, formation or zone is being talked about in the lease addendum. If we ever get into a situation where we are dealing with formations deeper that those drilled in the past then there could be a problem as you state.
Again, thank for your post and encouragement.
I know Anadarko has leases on the Camp Marydale Road.