Replies to This Discussion

Permalink Reply by HBP on January 13, 2014 at 5:35

Good IP, and it is basic math, but will the increase production match up with the increase lateral?  Better said, if you go a section and a half, will you see something near 1.5X production of the conventional lateral. (Would a 6 BCF one section well be a 9BCF if drilled a section and a half). Jay eludes to it, but where will we find the economic limit of the lateral?

The royalty owner should also do some basic math because they will be paid by percentage of productive well bore.  So say you own in the section where the bore goes almost the length of the section (not the half lateral section), your royalty will be paid at the same interest decimal for that unit, but only at the percentage the lateral has in that unit (lets say its 65% for that unit).  So if you are only getting 65% of your decimal paid, you will need the well to be that 1.5X to match what you would have received if they had just produced it with one regular section length lateral.

I'll wait for the data, but if the production doesn't match up with length, then the cross unit lateral benefits the company foremost, and maybe its that benefit that is allowing for these alts to be drilled under $5 gas (which I recognize), but do not assume that the longer lateral automatically equals a commensurate increase in production over the life of the well.  At some point in the lateral length experiment they are going to reach diminishing returns.  The data is too young yet to know if Encana drilled past it or still has it ahead.

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Permalink Reply by Skip Peel - Mineral Consultant on January 13, 2014 at 5:53

IP is a poor predictor of ultimate recovery but it's all we have for LA CULs at this time.  A few HA CULs have been drilled in E TX under Production Sharing Agreements.  The early production numbers are impressive and if they follow the projected decline curve will have Ultimate Recovery much greater than the earlier wells with short laterals drilled in close proximity.  Owing to the fact that un-fractured rock produces little or nothing in HA units, the incentive for operators is to eliminate, as much as possible, the unit boundary set backs.  In LA under the original 640 acre units 330' set backs theoretically  left un-fractured ~12.5% of the rock in the unit.  I agree that we will need more data to accurately evaluate the claimed benefits to CULs however in the interim instead of worrying about dilution of decimal interests my clients choose to be encouraged that unit production is significantly increased and waste (un-fractured rock) is avoided.

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Permalink Reply by HBP on January 13, 2014 at 7:28

I agree Skip that an owner may feel blessed to have the current development. 

So we will wait on data, but we should not take our eye of the issue of royalty owner dilution.   The game is to hold more with less.  Look at CHK's CULs in Caspiana, they barely fish-hook one of the 2 sections involved in each CUL.  So eventually that entire unit could be held by 5-10% of a productive well bore, while the other until with the CUL has 90%.  Sure, they can then drill more alts in the 5-10% unit to make it whole but eventually they run out of operated units to drill from and therefore units on the outskirts of this plan risk being held by very light production.      

I'm not trying to say this is alarming, I just think we should all understand the risk/benefits to the owner. 

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Permalink Reply by Skip Peel - Mineral Consultant on January 13, 2014 at 7:42

HBP, if you wish to discuss specific instances please post the unit.  I am seeing a number of variations in CUL designs among multiple operators.  Experimentation is to be expected and the maximum lateral length will firm up but always remain a function of specific local conditions.  I don't have any concerns for dilution of royalty interest because one would have to think that an operator would purposely do something inconsistent with good business practices.  In other words the best interest of the operator is to produce the maximum recoverable hydrocarbons in the most efficient manner.  That approach also benefits the royalty interests. The bulk of CUL wells are drilled as alternate unit wells therefore the leases are already held by production.  IMO the thought of the possibility of holding leases in a unit with a CUL that includes only a fractional portion of that unit is not related to dilution of mineral interest so much as it is related to timing of continuing development.

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Permalink Reply by 1kw6x71km1v37 on January 13, 2014 at 7:43

At some point, the reduced production capability of a CUL will leave some hydrocarbons behind. A valid claim to shorten a proposed lateral for increased efficiency/maximum drainage can be made at a well's Conservation Dept. hearing. The Commissioner is charged by statute to prevent waste such as this. The state also has a vested interest in maximizing recovery in the interest of maximizing severance tax revenue. No matter any increase in cost to the operator to do so, that is the way it rolls. It's one way the state can be made to work to your benefit.

Addressing the issue of hydrocarbons in the unfractured space between wells, that is being handled in the Austin Chalk by drilling a new unit well offset from the original wellbore towards the edge of the unit.

Of course, it is highly suspect that the above drilling is being done in order to generate some production in order to retain the current leaseholds. The economics of such secondary activity on such limited acreage is dubious at best until the prospect of future exploration in the Wilcox and Tuscaloosa formations is factored in.

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Permalink Reply by tc on January 13, 2014 at 8:35

"The state also has a vested interest in maximizing recovery in the interest of maximizing severance tax revenue. No matter any increase in cost to the operator to do so, that is the way it rolls."

Thank-you LA, for your state stupidity, PA and other marcellus shale states will gladly take your former Haynesville operators and allow them to make a profit.  Then the Haynesville will become like the old gold towns of the west, a ghost town.

Obviously I am being overly dramatic, but one thing we have learn (or at least some people) in the Northeast is that when states try to maximize their revenue (or unions maximize worker pay) no matter the cost, business will go elsewhere.

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Permalink Reply by Skip Peel - Mineral Consultant on January 13, 2014 at 10:24

The state does not force operators to perform exploration operations that increase cost per se.  If fact the state regularly approves cost saving changes in operations if they are believed to be compatible with the DNR/OOC's mandate to encourage development and conserve natural resources.  The approval of CULs is a good example.  From a regulatory standpoint LA is a very industry friendly state. 

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Permalink Reply by Skip Peel - Mineral Consultant on January 13, 2014 at 10:42

Gotta pay the piper.

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Permalink Reply by Spring Branch,mineral owner on January 13, 2014 at 11:24

Or how about the State standing by and letting all these Legacy Lawsuits be filed by shady (at best) lawyers!  Nothing will run the Oil & Gas Operators out of this state faster than this issue.

Permalink Reply by Two Dogs, Pirate on January 13, 2014 at 12:01

I'm with you on that one SB. I wonder if that is the reason work is so slow here in LA.

Permalink Reply by Two Dogs, Pirate on January 13, 2014 at 16:15

David Crocket asked me to look into two new permits issued today in LaSalle Parish. She thought the wells were pretty deep for that parish 13000 MD & 19000 TD. Turns out someone put a parish code of 30 instead of 31 Lincoln Parish. The permits are to Wildhorse for LCV wells in Section 14-T19N-R4W.  Keep on trucking Wildhorse.

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Permalink Reply by Henry on January 14, 2014 at 1:04

A question....  In principle, the cross-unit laterals could be almost 10,000 feet long, right?  (I get this by taking 5280 X 2 minus 660 feet..)  Is there a reason that ECA has limited their CULs to about 7500 feet in length?

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