Larry if you do not mind what is Contnental getting for price for oil and for gas, just wondering our well is just starting to produce.
Francis-That is a telling number. Playing the production out per unit to even six or four wells per unit says the price you sell your minerals for is undervalued. Remember though, that whoever is buying it has to make a profit long term on it. Otherwise, they would not be buying it.
Also, take into consideration that the multiple wells per unit will not happen just bang, bang, bang. With the history of production, gas wells length of productioj becoming more predictable. The operators do not have to drill additional well quickly in a unit. It will depend on prices primarily and the goals of the company .
A successful well in a unit probably means at least a ten year production period for that well. That lease that the well was drilled under will establish what is called HBP (Held By Production), meaning that well will hold that lease for probably ten years as long as it is producing something, and that something may not be very much eight to ten years out. So a company does not need to be in a rush to add the three to seven other wells a unit might hold.
There are mineral interest owners that will experience some sad experiences as all this plays out. Even though they have a successful well in their unit, the next unit has more wells in it in a short period of time. Probably different companies with different goals. And no, the multiple wells in the next unit are not “draining” the unit with only one well in it. Very tight shale gas production drains from a relativity small radius around the horizontal lateral fracture zone. If there was the ability to drain a 640 with one well why are companies planning on drilling as many as eight?
Also, companies may sell their producing units from time to time. They are making the same calculation that an individual mineral owner makes in selling their interest, only much more complicated and for many more $$. By the same token, whoever buys producing units from an operator believes they can make a profit out of the purchase. Otherwise, no sale.
I have been watching all the posts so will jump in. Our well is in section 1, 16N 14W Dewey county. Drilling was finished end of April 2011. Fracturing finished by end May, 2011. First gas sold JUNE 2011 and first oil sold in jULY of 2011. Our first check came late Feb. this year but no interest paid on that check or the March check so intend to contact them. The well came in at 105 bopd and gas at 2.1 Million cfpd. Don maybe you can help me understand the product codes on our remittance from Continental Resourses.They list 4 product codes at top of the remiitance. 1xx for Oil, 2xx for Gas in mcf, 3xx for condensate and 4xx for plant products. We are getting paid on codes 200, 203, and 300. Payment for 200 is very small, Payment for 203 and 300 are much better and pretty close to the same $ amount. We are not getting paid on Code 1xx. I called them and they said the 300 was for the oil. Would the code 203 be for galls liquids? If you or anyone is familiar with CR payment codes I would appreciate your explanation. Well dropped off pretty fast first 6 months but seems to be leveling out now.
Larry i am going to take a guess and say the code 200 is for 1000 mcf gas and since it has a higher btu level because of the oil you get a higher then market price. i would think the code 203 would be the bi products they are getting off the gas, i am not sure, someone can correct me. IT looks like Continental is getting some decent prices for their product, Thanks for the information.
Also keep in mind that those gas prices are hedged contract prices. As soon as those contracts are expired, the 5.80 per mmcf will settle to 2.00 per mmcf and drilling season will be over. The bust may come sooner than later unfortunately. Prices must be at least 3.50 per mmcf for drilling to be profitable. Those with good oil production will continue in the boom which looks to be most of Grady and half of Canadian.
Don. After 6 months production was down 35% to 40%.
Thanks Larry, right on the decline curve.
The only bogus thing is that the company uses MY farmland in MY section to drill a well under SOMEONE ELSES land. I understand how directional drilling works, but the royalty for that well wont be paid to me, I just get to loose some useable top soil. BTW this is an open general thread not a payment thread. I guess if you were loosing some land without compensation you might think differently? Funny you complain about my complaint. LOL I think I have a valid one. Yours not so much.
To anyone: Do the horizontal wells have a set direction like north to south or south to north etc? A well head in sec 2 drilled into sec 35 and a well head in 35 drilled into sec 2. Could well heads in any other sections come into 35 besides from section 2? I don’t know sections are laid out. Thanks
Last check showed code 300 (oil) at a little over $100 for Feb. Code 200 was 3.72 and code 203 was 4.17 for December and Jan respectivley. Those codes have me confused.
On selling your rights… We have a good well, deffinitely not the best well but a good one. We are getting between 100.00 - 150.00 per acre after a year+ of production. If you had 10 acres and sold those rights for 4500.00 each you would recieve 45,000.00 right? That would be less than 3 years production from one well. They are planning to drill 8 wells in many of those sections. When you multiply those production numbers to 8x. Then they are paying you less than four months worth of production. I wouldnt sell for 10,000.00 per acre.
Francis, You are assuming that oil prices will remain the same. They will change over the next 10 years but who know which way. 3 years ago it was around $40 a barrel, 4 years ago $135. From the late 80s to early 2000s it was $20-$30. You really never know. I also have records on a few wells the were decent producers for about 2-4 years and then produced almost nothing for the next 4-5 before they were plugged. In some cases the well lost money for the investors.
On the other hand I’m seeing new interest in sections with plugged wells, dry holes, (or wells with very low production.) In many cases it has been 30-60 years since there has been any activity.
When entry is made in one section and bottom hole in another, it is called directional drilling. Many wells are horizontal now. You should be grateful they continue to drill than claiming it is bogus.
Stephanie, I completely missed the thread on that. Was it intended for another forum? BTW I agree with you!
??? Stephanie-
Don Underwood GG (Geologist/Geophysicist)
Who is claiming what is bogus? I agree with your first two statments but the third is somewhat confusing.
Thank you Stephanie. Everything is starting to make more sense after viewing that public land survey.
Francis, I have had wells on our land that were for the benefit of others. Just as the others have wells on their land that benefit me and others. Its kind of a give and take thing like I said before.
Thanks Stephanie. Uh…because I agreed with you? lol
If the surface is in a different unit (i.e., section in most cases) than the minerals, there is no right to reasonable use of the surface to explore for and produce the minerals. If a well is being drilled on your surface with a bottom hole location in another unit, you must have consented to the use. To my knowledge there is no mechanism in Oklahoma to allow a mineral owner to use surface that is not in the same unit as the minerals. If an operator used surface that is not in the same unit as the minerals without consent of the surface owner, I would say that the operator has a problem because they are trespassing.
Thanks Gary. A year or so ago you were sitting here by your lonesome. Look what you started, 78 members!