Replies to This Discussion

Permalink Reply by w.r. frank on August 6, 2014 at 9:23

CHK (wouldn't you know it) has filed for CULs covering two sections, but only drills 330' into one section. You should not be able to hold a whole section with 330' of perforations. Currently, if you have a 640 acre unit, you can get approximately 4600' of lateral (5280 minus 330' minus 330'). IMO, to HBP two sections using CUL, the operator should be required to perforate and produce at least 4400' in EACH section.

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Permalink Reply by J B Nabors on August 8, 2014 at 5:49

I believe that your calculations may be faulty.   The setback for traditional wells is 330' from the unit border, but we need to remember that a horizontal well does not go down x feet, then do a right turn to begin the lateral.   It takes time and distance to bend steel pipe.   So in a traditional Horizontal Haynesville, the effective lateral for a 640 acre unit is 5280, less 330, less 330, less the horizontal curve distance of the bore hole.  I do not know what that distance may be, but I suspect that typically 1/8-1/4 mile of mineral bearing rock is not produced, or "wasted" in each unit.  

That is one reason the oil companies like to drill from one unit down into an adjacent unit.  That eliminates most or all of the bore curve wastage, for the producing unit, but still does nothing to solve the set-back wastage.  And I suspect that there will always be some wastage of the minerals directly below a horizontal pad. 

Obviously, it is profitable for the oil companies to drill one bore and HBP two or more entire units, with all of the associated leases.   From a conservation and exploitation point of view, ideally, one lateral might go 10 miles (I don't think that is technically feasible right now), because there is no 'wastage' for 10 miles/units.  The no wastage aspect is actually good for the mineral and royalty owners, too, since they are getting full value for their minerals.  Also, the driller only needs to build one pad, one time, so it is economical as well.   It follows that, if the driller's costs go down, pay-out occurs sooner, due to decreased costs and increased production, and UMIs will benefit.

One downside, of course, is the HBP issue.  Many royalty owners are still bound by leases signed when 1/8 royalty interest was the only option available.  IMO, they should have some opportunity for redress, or improved leases.    (One possible solution is to specify that ALL mineral owners within a particular HBP holding shall receive the same royalty payment as the highest existing lease within that holding. -- though I suspect that suggestion might meet some opposition)   

Another downside I see is the difficulty of determining ownership:   I suspect that the complexity of assigning and paying royalties for multiple unit wells is considerably greater than for a single unit.

Further, in light of continuing revelations about Oil Companies' unethical behaviors, it would be virtually impossible for any land or royalty owner to verify any royalty check received as to accuracy.   (It is difficult enough, now)

As Skip has pointed out, our O&G law was initially written nearly a century ago, and ALL of it -- until quite recently -- deals with vertical bores and issues.   The current century, with its technical advances in horizontal drilling and fraccing needs a lot of updating.   

I applaud the DNR for its efforts to spur discussion and to find some logically consistent framework, fair to both the royalty owner and the producer, to address this issue.

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Permalink Reply by Steve on August 8, 2014 at 10:01

Horizontal drilling poses new and complex issues for sure. I am not opposed to units of say 1200 acres if necessary to accomodate 8000 ft. laterals but certainly not the 1900-2400 acre units that some operators in the TMS are getting approved elsewhere and without any apparent opposition from landowners. I don't think they are getting 2000 acre units in the EF and it hasn't stifled development there.

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Permalink Reply by Skip Peel - Mineral Consultant on August 6, 2014 at 3:28

Sizing units to contain laterals entirely within their borders negates one of the advantages of CULs.  Namely the uu-fraced, and therefore unproduced, rock that is off limits because of set back regulations designed to prevent drainage outside the unit.  Regs regarding drainage were promulgated with vertical wells and conventional reservoirs in mind.  No one was thinking of horizontal wells or unconventional reservoirs 80 years ago.

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Permalink Reply by David on August 7, 2014 at 12:31

One concern with existing Non CUL & CUL would be the operator going back after first well production and changing unit size (smaller) which will cut out royalties to some who have already shared their "real" production with others.  So make the unit size stick, cannot be changed, per formation of that unit. Caddo, DeSoto, Bossier, Concordia royalty owner.

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