Looking for any input on what to really think about Continental’s application for the Driftwood Goddard Unit in Grady County 7N-6W
Its a big waterflood unit. They are hoping there is a lot of oil left in the formation. It could last for a long, long time.
What does this mean for royalty owners who currently have more than a 1/8 royalty?
ARTICLE 9 - INDIVIDUAL RELATIONSHIPS AND RIGHTS
9.5. Royalty Owners Free of Cost. A one-eighth (1/8) part of the Unitized Substances allocated to each Tract shall in all events be regarded as royalty, the proceeds thereof to be distributed to and among or the proceeds thereof paid to, the Royalty Owners free and clear of all Unit Expense and free of any lien.
Thanks Todd. So I’m guessing that you’re saying they’ll do some water injection wells trying to recover more oil than what they’re currently getting?
And what does the term Unit mean? Does that change the way people get paid? Get paid as a complete unit instead of off the section or sections the well bore travels through?
Where did you get your information? Curious, seems hard to find.
If the waterflood unit is approved, then the ownership of the unit will be reapportioned. Each mineral owner will be paid upon their royalty and their percentage of the net mineral acres divided by the much larger unit acres. Your decimal amount will change. Instead of being paid on a low number of wells with your original spacing, you will get paid of your percentage of the whole unit and all the wells.
This sounds like a good thing? I haven’t gotten the latest paperwork to vote to ratify it, yet…
I received my papers & the way it sounds I should vote in favor of it?
We have producing wells in two of the sections under this proposed unit. We also have an Exhibit A with our leases that protects us as mineral owners.
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Will this unitization negate the protections written into our Exhibit A and we will be forced to abide by only the legalities defined in the Unitization?
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How will this affect future wells that are not leased or on the books yet?
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Why does Continental want to do this? What is in it for them? They are not going to do anything that doesn’t improve their standing and profits and quite possibly at the mineral owner’s expense.
Thank you.
M. Wood
I have at least three producing well that would be swept into the unit. Doing fine w/o gas flood. Why would I sign up? Plus, looking at the deductions allowed it seems that my current royalty income could be slashed quite a bit. Amirite? Wells are Ramsey Trust 1, 2 and 3. Old timer Jim B.
In general, I have been very pleased to be included in a secondary or tertiary recovery waterflood or CO2 Flood fields. Although my original well decimal amount went down, I was then paid on EVERY well in the field at the new decimal. My wells may have ceased production depending upon where they are in the field but I am still paid on wells in other sections. Also, the increased pressure from water or gas flood has improved the production on my wells as long as they were alive. The goal of enhanced recovery is to get as much hydrocarbon out of the ground as possible and royalties into the mineral owners and working owners hands. As a mineral owner, I would want that. Our family has revenues from these types of recovery efforts going back decades since the enhanced recovery extends the life of the field quite a bit.
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Martha, our family pooled our property in this unit in order to get a higher royalty percentage. Sounds like Don B has the same concern. We are not protected by a lease in this case. Does that change how we should see this? What does that Article 9 mean?
I do not have a copy of Article 9. Your royalty percentage will stay the same unless there is some wording that changes it.
https://imaging.occ.ok.gov/AP/CaseFiles/occ30455173.pdf
Article 9 begins on page 240 and ends on page 241.
I received a generic copy of the proposed Driftwood Goddard Unit a few weeks back but only after receiving the detailed Plan of Unitization and Ratification Request this week do I really understand the questions/comments from Don and others. 40+ pages of Articles and Exhibits to describe the plan is surely beyond most mineral owner’s (and some lessee’s) ability to comprehend. That said, I sent an email to JackFork Land earlier this week with some generic questions (what mineral owner rights are being unitized, what affect would the unitization have on existing leases & Exhibit A’s, the 9b one from Don, etc.) but haven’t heard back from them yet.
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Let me give this a little input. The Goddard formation is a solution gas drive reservoir. Simply put, when under pressure, the gas mixes with the oil and water and up through the ground comes a bubbling crude. When the reservoir pressure drops to a certain point through production (bubble point), the gas no longer mixes with the oil and water and only the gas itself comes to the surface. That leaves millions of barrels of oil in the formation. Continental wants to re-inject this produced gas back into the reservoir to build the pressure back up so those millions of barrels of oil are produced. Without this process, the well where your minerals are, might be prematurely plugged because the oil doesn’t come to the surface by itself. A traditional pump jack won’t help much either as the oil won’t release from the surrounding rock without the lost pressure.
As for the 1/8th royalty, that is what every royalty owner will receive, free of any costs of the project. Here is the tricky part. As I understand it, your remaining royalty, if any, over and above the 1/8th, will absorb your proportional share of expenses to the whole project. You will get that royalty over and above the 1/8th but with some expenses taken out. The largest portion of that expense is injecting the natural gas. Some of the injected natural gas will come from existing wells in the Unit, some additional gas from the surrounding area producing from different formations will be purchased and injected. All of this greatly benefits every mineral owner because more oil is produced. At this time as with most of history, oil is much more valuable on a BTU basis than natural gas. Its a win/win situation for the mineral owners and will extend the life of all of the wells by years. I don’t know the permeability of the Goddard formation but wouldn’t be surprised if years down the road, the formation goes further into secondary recovery with the injection of water. If you are in your 50’s, chances are very good that this Unit will still be producing when you are gone. I doubt you can’t say that about any well in this Unit without this procedure. Remember, if the well where your minerals are located “drys up”, you will still get paid because when the Unit produces any oil, you will share proportionately in that production. As a mineral owner and a working interest owner, I am all for it. Hope this helps a little bit. It’s complicated.
Thanks Todd, great input.
While the technology and strategy behind enhancement (and the potential benefits thereof) seem fairly straight forward and desirable, it’s the complexity of the Plan that makes many involved uncomfortable. As mentioned earlier in this post, many have worked hard over the years to understand and negotiate favorable leases. The unknowns potentially hidden in the 40+ pages governing the Plan (such as capping “no deductions” at 1/8th) and potentially redefining years of well understood lease agreements are where most of my questions/concerns come from. As you said, it’s complicated… too bad Continental didn’t take a more straight forward, simpler approach to define the Plan as it relates to the typical mineral owner in the unitized area. I believe doing so would have made the decision to support ratification much easier for many involved.
Todd: Damrite it is complicated, and we do not have all the information we would like to have. For instance, what is the current average production per nma? Will un-enhanced production be thrown into the overall Unit pot? Seems so.
My concern exactly. My producing wells are to be tapped to make possible your non-productive acreage. I note that it is probably difficult or impossible to limit the Unit to those wells subject to periodic gas injection. That, I could be comfortable with. BTW, I am on my second pass at reading the whole mishmash. Tough on my old eyes. I note that the articles were apparently lifted from a unitization that included offshore production. Anyone know the history of the documents?
Mr. Brock: I’m not sure what average production per nma has to do with anything so help me with that. Also, what do you mean by un-enhanced production? Everything within the unit will be enhanced. I’m in some of the same wells that you are in. The Ramsey wells actually have some of the largest, if not the largest unit percentages in the whole thing. The reason for that is there are more acre feet of the Goddard formation in those wells and as a result, oil production will greatly benefit from the gas injection. It will take a little while for the formation to get re-pressurized but when it does, as M_Barnes says the life of the field will be extended quite a bit.