Todd: I forgot to mention that the enhancement seems to be on a well-by-well basis. Three months of injection followed by three months of production. Repeated ad Infinitum. Fifty percent down time when activated. Until then I sense that the wells will continue to produce unenhanced but the production is swept into Unit bucket.
This may be a fallout from modifying a document intended for use with regular wells including onshore and offshore. I have been trying to wrap my mind around how you can pressurize horizontal wells one by one. Maybe the idea is to pressurize the entire Unit at once but the document does not seem to be drafted with that in mind. If that is the intent, a lot of my concerns would be mitigated to some extent. I confess that I may be out of my depth, here. But, hell, I am 91 years old. So cut me some slack. Jim B
Todd: In my dotage I seem to see things others do not. But it seems to me that the Plan will normalize production over the entire Unit thus if my holdings are more productive than the average the excess is taken from me for redistribution; a smaller decimal interest over a larger but less productive whole will cost me money. This flows from the allocation of interests based on nma regardless of productivity w/o gas injection. This is a result of combining wells that are already productive with those that need a boost. Now, I may be wrong, and recognize that over the long haul my wells may produce more oil. But will I net more income than if there are a few more years before compelled unitization? That is why average production over the unit is .relevant when comparing it to my holdings. Sorry if my ramblings make no sense. Jim B
Still reading the Plan again. But I wonder how this is going to work. I guess my wells will gussy on, producing without gas boost, until that magic moment that the Unit springs into life. Then the wells no longer belong to me but instead to the group. So when does the injection start to benefit me as an individual royalty owner? And how many $$ do I sacrifice now in hopes of additional $$ at some indeterminate time in the future? What discount rate do I use to compare future income to lost present dollars? I thought the reason Continental was using horizontal drilling plus fracking was to access different areas of oil-bearing formations that could not be produced economically otherwise. So there is not a coherent “pool” to be produced, right? How is this going to work? I admit my ignorance … can somebody educate me?
I can answer some of the questions in general terms from a production geologist point of view for this type of secondary recovery. Maybe one of the petroleum engineers can comment at a more technical level regarding the technique.
Currently producing Goddard wells will continue to decline very rapidly as they have not much “lift power” left to get the oil out. The reservoir pressure is sinking fast. (Think of a dead champagne bottle. Good stuff stuck at the bottom of the bottle and no way to get out. "Your “gussy along” done “gussied out”) Your volume and hence income will decline rapidly. If the injection of gas is allowed, the injected gas will re-pressure the reservoir and the pressure front will hit the wells. The wells’ volumes are expected to improve at that point. The timing for each well will depend upon location and the pressure front and timing of the pulses The gas injection generally benefits everyone-otherwise the field as a whole will die very quickly and everyone will lose as the oil is too heavy to get out of the reservoir without the lift of the gas bubbles. They can do this sort of cycling over and over again with great success and get more and more oil out of the reservoir by “re-using” the gas.
Instead of one - four wells at 640 acre spacing, each mineral owner now shares in production from all the Goddard wells in the approximately 39.5 sections (~25,250 acres-quick guess, I didn’t add them all up) See map p. 196. Each tract will have a new number and the percentage of that tract has a participation factor in the whole unit. (p. 203). For every dollar in sales for the whole field, you get that new percentage. Otherwise, if your wells die, you get nothing. If your well eventually dies, you still get paid on the rest of the wells in this scenario. Page 214 shows all of the current wells coded by reservoir. Look for the Goddard colored wells that everyone would now share to their production. Think of this as a rising tide that floats all boats. Everyone benefits. Page 221 lists the wells and their reservoirs.
These sort of documents do seem complicated at a first reading. This sort of secondary recovery has been used for decades and is generally very successful and can extend the life of the field by vast volumes and many decades. The horizontal wells were drilled and fracked to allow the larger oil molecules to migrate through very low porosity (the holes in the rock) and low permeability (the connection between the holes-think bar of a barbell). Gas molecules are tiny. They can wiggle around tiny holes and skinny openings between holes. The oil cannot. The molecules are very large. They need the frac to make bigger openings and they need the gas bubbles to push those large molecules along. Once the reservoir goes below the bubble point, there is not enough pressure to push the oil molecules and they get stuck and stay in the reservoir. (Stranded semi trucks on a highway with tiny scooters zipping past in tiny spaces.) Another important thing to know is that once the oil stream flow is broken, it is very hard to get started again. That is why they want to start this injection now, before they lose too much gas pressure.
Martha: Thanks a heap. I admit that I am mostly ignorant with respect to geology of oil production. And that is why these things bother me so much. I can, however, read what is in a document and it seems to me that Continental is the big beneficiary here as compared to royalty owners. We are paying for the gas injection costs via a reduction in royalty (that apparently is permanent) and free use of gas that otherwise would be marketed. But the question is whether to approve or not and long-term as you point out more oil will be produced. Not the first time I have had to bite the bullet. Again, many thanks for your patience. Jim B
Pretty sure the value of the enhanced oil recovery on a BTU basis will more than compensate for the gas injection costs.
Mr. Brock – I too am not an expert with the geology of oil production but after having spent time reading through the proposed unitization documents and it’s terms, I’m also of the opinion that the Plan favors those producing the oil & gas vs. the royalty owners.
• As many other royalty owners have done, I negotiated hard to sign a favorable lease with much more than 1/8th royalty and a good Exhibit A (including no deductions). Having to pay expenses on royalty greater than 1/8th could be a big deal (even with the proposed increase in production). In general, it appears that the Plan supersedes current leases and overrides most lease terms except royalty percentage.
• Also, my royalty interests affected by this unitization exist in a portion of the Unit where royalties from natural gas often exceed those of oil but “the formula” used to assign the weighted values of tract participation for each section relative to the Unit appear to be based on oil recovery & reserves. Assuming that natural gas is also a shared resource across the Unit, those in sections with higher natural gas production take a hit.
At this point, I’m in favor of unitization and enhanced oil recovery but am leaning to take a pass on unitization under these terms.
GD1: In case you did not get my reply by email: You will make out like a bandit. My wells are in the oil producing area of the SCOOP, but if my wells were gassers I’d sign up in a minute. Jim
Mr. Brock - Sorry, I did not receive an email from you but assume it was similar to your latest post re: gas wells within the proposed Unit. I’m not sure how having a good gas well within the unitized area turns out to be “bandit” level good.
That said, it is not clear to me as to whether natural gas and/or oil produced from non-Goddard formations within the unitized area (i.e the Woodford) is or is not considered to be a shared resource across the Unit as a “unitized substance”, I can read it both ways…
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If it is not included then I assume there is no change in royalty calculations (including no 1/8th “no deduction” cap) and that sales are shared within the section as per our usual lease terms. Status quo.
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If it is included, then are the proceeds then proportionately shared across the Unit and included in the “equation” used to determine participation within the unit.
FYI… I asked JackFork Land several question along these lines over a week ago but unfortunately have not heard back from them.
I assume that you have received the paperwork for Unitization. So I guess you are part of the crowd.
Mr. BROCK - Yes, definately part of the crowd. I think we’re all becoming much more aware of the complexities associated with the proposed Goddard unification and unfortunately, its my experience that complexity seldom works in favor of the minority (and in this case, it seems that’s us… the mineral owner). Thanks for all of your input and support!
Our local is in the E/2, E/2 of both 18 & 19 7N 5W and forced pooled at 1/4. The unit is mostly in 6W. Spoke with Jackfork regarding any interference with drilling in the prolific Springer. Any input. Tom
The Goddard is part of the Springer.
That means Continental is force pooling the Springer an entire Range+
I am relating unitization of an entire Range being akin to holding the Springer formation in 6W.
Don - FYI… regarding your earlier 9.5 Royalty Owners Free of Cost question, I have been told in general terms that this does not apply to those Royalty Owners who are leased; that this applies to force pooled owners and owners that are in suspense.
In summary, I can’t speak to the specifics or accuracy of the above but believe it to be true based on the source. It does make sense to me that the Plan could not override the terms of a signed OGL agreement but the language within the Plan is not clear along those lines.
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Martha: Us old guys can’t spend British Thermal Units, this my focus on dollars.
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Good one! The higher the BTU, the higher the dollars! Oil has the highest BTU, graded by API value, rich wet gas comes next and then dry lean gas. As an engineer friend of mine said, “We are not in the business of Oil and Gas, we are in the business of Pressure” No pressure to flow oil and gas, no production, no dollars. Pressure either has to be natural or it has to be enhanced or we get very little or no returns up the borehole to the bank.
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As of now, my wells have good production. Maybe I will change my mind when it begins to drop off. But thanks, Martha, for your explanation. Jim