For the mineral rights owner in 1 640 section. Would it be better or worse for 640 or 1280 spacing units? Thoughts opinions. A 1280 unit is a 10000 foot well a 640 unit is a 5000 foot well. The cost to drill a 10000 foot well is less in cost. Than 2 5000 wells in a 640 unit. However, with a 640 unit spacing, you are only sharing production with 640 NMAs and not 1280 NMA as with a 10K foot well. A 10K well since covers more of the pay formation twice as much will it produce twice as much production for twice as long. If it did then one would prefer a 1280 unit rather than a 640, however, if it doesn't then one would prefer a 640 unit. For a 1280 unit will cut your revenue in half from a 640 unit.
I certainly prefer shorter leg oil wells where 70% likely comes from the first 4500 feet. I seriously doubt the second 5000 feet of a gas well produces as much because I keep reading about the "Differential" of production attributed to each section on the Oklahoma forums. To me? The long 10,000 foot laterals sound like they leave a huge amount of the resource in the ground which may never be recovered.
Bear in mind, You have no choice whether your well's lateral leg will be 5,000 or 10,000 feet.
Like a lot of things, this question is not as simple as one might guess. Longer laterals make more oil than shorter laterals, although it doesn't necessarily scale up proportionately due to various technical reasons. Longer laterals are cheaper to drill on a dollars per lateral foot basis, since you only have to drill one vertical section as opposed to two (or more).
From a mineral owner's point of view, shorter laterals would be preferable since all you care about is making as much oil as possible.
However, from the Operator's perspective, their objective is to maximize the return on their investment. In that case, even though a longer lateral well may not recover as much oil as two shorter lateral wells, the cost savings from drilling one well versus two may actually make the economics more attractive.
Different plays and even different areas within a given play will give different results. Further, the price of oil is a big factor in the analysis. When oil is higher, the added costs of drilling two wells versus one might be worth it, but when oil is lower the savings in drilling cost will win out.
The more sections the more wells that can be drilled and in production. The mineral interest will be your net acres over total acres in the unit so the more wells the more acres you have. Longer the laterals the more oil play. If the wells come in good they will drill more. Obviously the more acres the more wells.
There are several points here. First is that it is more economic to drill 10,000 foot lateral across the 2 sections. Second, it is not in the mineral owner’s best interest if only one well is drilled and holds 1280 acres. It would be better to have a 640 acre unit which is holding only 320 acres in each section. For example, the N/2 of Section A and N/2 of Section B. A second unit could be formed in S/2 of each section. If the operator guarantees 2 wells, then the larger unit could be acceptable. If your lease allows the operator to have unlimited right to pool, then there is really nothing that you can do about this. If you lease requires consent to pool or limits the maximum acreage in a unit, then you can object to a single well holding 1280 acres. Third, the other problem is when a unit is formed on such huge acreage and it is not limited to horizontal wells. Then you are faced with having a single vertical well holding 1280 acres.