Virginia, Yes, I agree and will get OCC info back to you asap.
Martha,
Thank you. I knew they were putting salt water in the Arbuckle because it had the largest area and was porosity. But, I think they are putting the brine in there also, yet this article is showing a different place. Very interesting.
If a disposal well is drilled, do mineral rights owners receive any proceeds?
Virginia, the holidays has slowed my multi unit research down, but friend at the OCC should be returning next week. Yet, from what I can determine the OCC allows production from two 640 acre units without establishing a 1280 acre unit, so both units do not have to share equally on the production. That’s way the lateral lengths in each section can be used to determine the royalty percentages paid. However, if a well is drilled into a unit a few hundred feet the precentage is only 2 or 3 percent, but the O/G company can still hold that unit by production. This “multi 640 rule” only works if every oil and gas company is treats every mineral owner fair and square.
Excuse the typo’s I’m in a hurry. Got to take the dog to the vet.
Martha,
I think you are saying the same thing I am. From what I have been told and read, if they drill a few 100 feet into the 2nd section, it still holds the whole 640 A and that group of people who own the 2nd 640 would share whatever the 100 feet produces. But, I think there is more to it than that. I think it’s fair if they drill 2 section and they both share equal, then the O/G company can hold the 2 section. But, my understanding they take into account how many holes have been shots, lateral lengths, etc. And I think the acreage is spaced as multiunit holding for a total of 1280 A spacing. It’s not spaced 1280 A like in N D, but it’s about the same. I still have lots of unanswered question on it. I can see how the investor could drill more wells and the mineral owners would gain from that.
Virginia, Devon drilled a vertical salt water disposal well in Payne Co in the section beneath me in Sec 19-19N-01W and they are injecting all the water into the Arbuckle dolomite formation. Recently I read a report stating that Chesapeake, Devon and some other companies have proven the Arbuckle is the best formation for salt water disposal, so I looked at Sec 19 and sure enough it was drilled to the Arbuckle which is the recorded disposal formation for that section. Here’s another article reporting: “Arbuckle dolomite creates an almost perfect waste disposal zone”. http://academic.emporia.edu/schulmem/hydro/TERM%20PROJECTS/2010/Fab…
Now, I have no problem with them finding the best formation to inject, but The Arbuckle can be injected for enhanced oil recovery (EOR) and here’s a report on that subject. http://www.netl.doe.gov/publications/proceedings/07/carbon-seq/data…
John Thronton, The surface owner is paid for every barrel of saltwater that goes down the hole, but the mineral owner is not entitled to any of the surface owners payment unless they own the surface too. Water flooding is another topic though and I’m wondering…does the salt water well change from a disposal well to enhancement oil recovery injection well (EOR) if an oil and gas company is injecting salt water into a formation which will ultimately enhance the recovery of oil?
Martha,
Usually the disposal well is drilled into an area/sand that doesn’t produce.
The water flood is in a producing sand and takes several wells pumping the same pressure or similar pressure. I have never heard of a disposal well being used for water flood, but new things are happening all the time.
Lots of oil companies are buying a small tract of land for the disposal wells and then using it for a drilling pad also. Same oil companies will pay for surface damage and then so much per barrel. Be sure to get electronic measurement if you have a disposal well. Also, find out if they will be trucking to the well or will it be from lines. I have seen lots of farm dug up putting line in to get to the disposal well, but it’s still better than trucking.
Virginia, Here’s an article on CO2 (EOR) which moves the oil and water, but it says they may have to re-pressurize the formation with water first! I believe this is why they are injecting salt water into the Arbuckle dolomite and the OCC should make them report that they are doing so to enchase oil recovery (EOR). Read page 5… http://www.netl.doe.gov/technologies/oil-gas/publications/EP/small_…
“For this reason, oil field operators must consider the pressure of a depleted oil reservoir when evaluating its suitability for CO2 enhanced oil recovery. Low pressured reservoirs may need to be re-pressurized by injecting water (see page 6 sidebar on waterflooding).”
Virginia, If you thought injecting the Arbuckle formation was interesting you will find “in situ” oil shale processing even more fascinating. I do believe this is also highly possible. Remember, Devon is partnered with Sinopec, the Chinese company in our drilling areas. Read page 2 where it begins: “An attractive alternative to surface retorting process is the in situ retorting process. There are many reasons to develop in situ techniques for recovery of the oil from oil shale.” http://www.eolss.net/Sample-Chapters/C08/E3-04-04-03.pdf
Martha,
I just found my notes from a Town Hall meeting in Perry, OK on Aug 22, 2013, where OCC, NARO, OERB & Devon gave some good information.
During this meeting, Dana Murphy from OCC told us about multiunit horizontal spacing. They also gave us a booklet on basic information. My notes states, several things are considered in multiunit spacing. And they were still working to solve several problems. Today, I got my leaflet from NARO and in 2014, looks like they maybe looking at multiunit.
I’m still not sure it’s good for the mineral owner as it will hold 1280 A, so one well can keep you from getting another bonus.
Thanks Virginia, The OCC has a duty to ensure the common good of the general public and mineral owners are not considered “the general public”. My project for next week is to find the facts on multiunits, so we can determine if it will harm or help.
Martha,
You have the same information that I had. The length, plus perforations and I think their are a few more things involved, but I’m not sure what they are. How will the mineral owner know for sure how many perforation there are. That is why the law was wrote so general terms. It is my understanding that NARO will be help write the new law. But, I’m still thinking a person will only get a few dollars per month and it could whole the lease for years without new bonuses. Lets said, the well only came in at 100 bbd. You get 3/16 of the spacing (1280), at $100 a barrel, that is only $1.46 per A. per month. It’s soon going to cost the oil company more to sent the check than what the check is worth, let alone the gas to get it to the bank.
Martha,
I feel we may know each other. What was your maiden name?
If you heard we can voice our opinion somewhere on 1280 spacing and setting new rules to increase density within a reasonable time , let me know. I will make the trip or write letters. I’m sure that OCC and the RRC are tired of hearing from me, but i keep thinking they will listen someday.
Virginia, I just spoke with a friend at OCC and was told that, at the present time, the 640 spacings are combined to make the 1280 multiunit spacing thus allowing the lateral length and number of perfs to determine the mineral owner’s percentage of production in a given section. She was somewhat uncertain on the calculations of the number of perforations allowed for specific formations, because many of the wells that have been drilled are classified as ‘test wells’ and the operators were given great latitude to “test” the number of perfs and lateral lengths. However, I guess this testing time has run it’s course and now the OCC is going to have a Rule Hearing on the creation of 1280 acre multiunits, but they have not set a date and may not post the date of the hearing. I have placed another call to a highly informed individual who may be able to tell us if we will have an opportunity to protest or speak on the behalf of royalty owners. My guess is that since this is a “Rule Hearing” we will not have a voice and will not know the specifics of the new rule(s) until they are legally presented to the public.
Virginia, My questions are the same as yours and I’ve called someone who should be able to address some of our concerns and now waiting on return call. Your concerns are highly valid and recognized by NARO, because a whole section could be held by a 1280 A spaced one well multiunit unless the OCC sets “field rules” on increased density.
Virginia, I don’t know of any relatives in the Woodward area, but used to know a Virginia Reger who lived in Woodward. She owned the ranch next to mine at junction I-35 and Hwy 51 west of Stillwater.
Virginia, My maiden name was Phillips, but my friends say I’m an old soul, so we might have known each other before.
Martha,
Do you have relation near the Woodward area? We need to go on the friends part of this site if you do.