Replies to This Discussion

Permalink Reply by Joe Aldridge on January 24, 2011 at 5:14

Skip, I have someone that I can go to and answer the last questions that you ask. I'll see what I can find out. It maybe a week or so.

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Permalink Reply by Skip Peel - Mineral Consultant on January 24, 2011 at 5:19

It's worth the wait.  Thanks, Joe.

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Permalink Reply by drilltheshale on January 24, 2011 at 6:45

From a layman's viewpoint, I think "larger" units make a lot of us nervous.  I understand why units might need to be "shaped" but why necessarily larger, and how much larger?  Will parts of units just be left out altogether.  What does this mean for existing units and can leasing companies arbitrarily drop leases?

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Permalink Reply by Skip Peel - Mineral Consultant on January 24, 2011 at 7:07

Larger units dilute a lessor's proportional interest in unit production but those larger units allow for more unit wells.  Would you rather have a 1/100th. of a percent of eight wells or 8/1000th. of ten wells.  That's just an example off the top of my head so please don't go running for your calculator.  Regardless of size the 80 acre spacing rule applies.  Therefore a 800 acre unit would qualify for 10 wells.  The anti-industry vindictive on the site keeps many from thinking rationally about subjects like this.  Consider it this way, would an operator do something to hurt lessors if it also hurt them? The important thing to remember is that larger than 640 acre units should be allowed only where there is a compelling reason.  Units that take in large areas under Toledo Bend are a good non-fault example of larger than normal units formed because there has to be dry drill sites to produce the unit.  The size of the unit pertains to the length of the lateral.  No operator, and no knowledgeable lessor, wants a well with a lateral less than say 4500'.  The reason is economics and expensive wells with short laterals don't make economic sense.   Operators in situations where they can not drill a lateral of a reasonable minimum length may just choose to drill one less well.  No operator is going to walk away from one single economic mcf  they think they can produce in a unit.  And those lessors where faults exist and units can not be drawn to address the problem will receive reduced royalty income.

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Permalink Reply by Joe Aldridge on January 24, 2011 at 7:29

That was not allowed to happen when the Port Hudson and Irene Fields came together. The Commission made it a point to make sure that the units were the same geographic size. I don't know if that has changed - I would hope that it hasn't. I'm the one that put an end to Exxon's request for larger units in that case and I heard later that all units were going to be required to be the same in a particular field. Also, you as mineral/royalty owner can put in a comment before the Commission at the unitization hearing. The Commission listens.

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Permalink Reply by Skip Peel - Mineral Consultant on January 24, 2011 at 7:31

Joe, were the Port Hudson and Irene Fields developed with horizontal wells?

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Permalink Reply by Joe Aldridge on January 24, 2011 at 7:43

No they were not.

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Permalink Reply by Skip Peel - Mineral Consultant on January 24, 2011 at 7:55

Joe, one of my points in this discussion is to suggest that horizontal development is materially different in many important respects from what has come before and requires a change in the way we view the dynamics of O&G exploration and production and the way the state regulates it.

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