determining a unit

Does anyone know if a unit is predetermined prior to the application for a gas well permit?

Views: 3521

▶ Reply to This

Replies to This Discussion

Permalink Reply by Stephanie Lindquist on May 19, 2013 at 11:09am

Thank you! Southwestern has a potential well going in 1000 feet from my water well, however we are not leased with them and our lease term ends next month. Still waiting for more info from them and to see when they apply for the permit.

Permalink Reply by jnm on May 19, 2013 at 1:35pm

The unit showed on the plat map that goes in with the application is always smaller that the actual production unit.

Permalink Reply by Kathleen on May 19, 2013 at 1:56pm
I agree that happens most of the time, and that's what some people find so confusing. I know it took me a long time to prove most units where bigger than the drawings on the ODNR site.
It just made no sense that most of these wells around here (OH) were showing 150-160 size units. I knew they had to be bigger.
Permalink Reply by Joseph-Ohio on May 20, 2013 at 12:48am

An observation:

The more horizontal laterals connected to a single vertical bore to depth the more complicated the bends / offsets get.

A 90 degree bend from vertical to horizontal takes a 500' radius (for a 6" dia. bore) as I have it.

The larger the bore the larger the required radius to change direction is.

The smaller the bore the smaller the required radius to change direction is.

A single horizontal lateral per single dedicated vertical would seem to me to be the most simple to develop.

Perhaps two horizontal laterals running away in opposite directions from a single dedicated vertical would be pretty easy to develop.

If you had three horizontal laterals connected to single vertical and all of the horizontal laterals were running away from the single vertical parallel to each other / traversing in the same direction; two of the bends would be compounded and tougher I think to develop.

The more real estate it takes to bend the bore into it's final horizontal lateral position the more real estate is left undrained; as I understand that only the horizontal portion is fractured.

For those reasons it seems to me that the more laterals that are connected to a single lateral the more inefficiently the real estate is drained of it's resources.

Makes sense to me anyway - anyone else see things differently or know of a correction to this  perspective / observation ?

 

Permalink Reply by Tom R on May 20, 2013 at 3:39am

I don't know if there is someplace where there are multiple horizontals off the same vertical bore, but in my area of NE PA it is strictly one horizontal per vertical. Years back, when things were just starting up, various companies held informational meetings and all took pains to dispel the idea that the wells were developed anything like an umbrella (multiple legs off the same shaft). Even leaving aside the complex bending considerations I would think that it would be a problem in sealing the "branch" points to maintain well integrity and avoid gas migration out of the well.

Permalink Reply by Jack Straw on May 20, 2013 at 3:40am

Joseph, you are laboring under a number of misconceptions.

 

RE: “The more horizontal laterals connected to a single vertical bore to depth the more complicated the bends / offsets get.”

 

Each horizontal lateral is kicked off from a separate vertical.

Multiple horizontal laterals are NOT connected to a single vertical.

On a pad with multiple wells, they drill one vertical kicked off to one horizontal; then they move the rig over a short distance and drill a second vertical kicked off to yet another horizontal; ; then they move the rig over a short distance and …….

Multiple horizontals are NOT connected to a single vertical well bore.

 

Another misconception, the “vertical” portion of the well is not typically vertical; they directionally drill to the point at which they need to build angle from (near) vertical to horizontal.

The “vertical” is not truly vertical; but is directionally drilled to a predetermined subsurface point (prior to beginning to make the transition to horizontal).

More wells drilled from a particular well pad does not mean that more subsurface is left undrained.

 

We find it easier to visualize matters as two-dimensional on a computer screen or on a piece of paper, what is really happening is a “dance” in three dimensions as the wells gently “snake” down in a manner that eliminates the need for exaggerated sharp bends in order to reach the point at which they go horizontal. When you see well bores (drilled in 3D space) projected onto a 2D piece of paper, you lose perspective as to what is the "real" path of the well bore. 

 

JS

Permalink Reply by Joseph-Ohio on May 20, 2013 at 4:02am

Thank you Mr. Jack Straw.

Then (if I understand your post correctly) if (for instance) four (4) parallel laterals were 600' apart (at depth) then there would be four (4) verticals rather closely spaced together on the well pad and each then would 'kick-off' vertical and compound offset (dance) to the final location of the deep horizontal lateral. 

And, also, if each horizontal lateral (at depth) began 500' away from it's vertical (500' away in the direction of the horizontal lateral's vector); the minimum 500' bend radius rule could still be honored throughout the downward dance (I guess).

Kindly straighten me out if I still have it wrong - thanks again, I appreciate it.

J-O

 

Permalink Reply by Jack Straw on May 20, 2013 at 4:45am

RE: “Then (if I understand your post correctly) if (for instance) four (4) parallel laterals were 600' apart (at depth) then there would be four (4) verticals rather closely spaced together on the well pad and each then would 'kick-off' vertical and compound offset (dance) to the final location of the deep horizontal lateral.”

 

Correct, the surface location of the four wells would be closely spaced – the wells diverging in space from one another with increasing depth.

 

RE: “the minimum 500' bend radius rule could still be honored throughout the downward dance”

 

500’ is a minimum, they can choose to have a more gentle (larger) radius.

 

Remembering that we are working in 3D space, let’s assume a situation in which four wells are drilled from a single pad; two wells drilled horizontally to the NNW and two wells drilled horizontally to the SSE.

It would be possible to directionally drill the wells which will ultimately go horizontal to the NNW in a manner such that the “vertical” portion initially wanders to the SSE … and then goes horizontal in a NNW direction (no +/- 500’ dead zone left undrained). Likewise, wells which will ultimately go horizontal to the SSE can be drilled in a manner such that the “vertical” portion initially wanders to the NNW.

 

Current drilling technology allows wells to accurately follow detailed trajectories.

 

JS

 

Permalink Reply by John OBrien, landowner advocate on May 20, 2013 at 2:41pm

OK Jack, 

Here is a question for you.  Monroe County, Washington Twp, HG/Whitacre units 701 and 702.  ODNR well finder map shows the normal NW and SE drilling horizontal directions on 701.  Now look at 702.  One of the horizontal "wells" completely ignores the norm.  It is shown actually crossing two or three of the 701 horizontals.  Can you please explain why this might be?

It doesn't seem right especially if you look at who's land it covers.  How can they ever know who to pay royalty to in such a situation?  

Thanks

Permalink Reply by Keith A Williams on May 20, 2013 at 1:40am

Stephanie et al,

I think there is a lot of confusion about units. In Ohio, the unit on the plot maps submitted to the ODNR is to show that the company has a DRILLING UNIT that complies with ODNR requirements as to distance from other wells, property lines, etc. That DRILLING UNIT must be set up before the permit is approved!

The second type of unit is a PRODUCTION UNIT. This is the unit that describes who will be paid from the well procedes. It must be registered at the county courthouse. I do not know all the rules that apply to these units.

The PRODUCTION UNIT is what determines the people that will be HBPed, payed etc.

HTH

Keith

Permalink Reply by Stephanie Lindquist on May 20, 2013 at 1:58am

If I'm understanding the fracking process there is a predetermined direction of horizontal drilling determined by the seismic testing. This is also determined by the natural fault lines etc. So if this is correct all this info would be considered when determining a production unit as well? 

Permalink Reply by Booger on May 20, 2013 at 9:41am

i am also confused about this......drilling units vs production units......i thought a unit was a unit.

i have a friend who has land just north of a chk pad.....the well goes in the opposite direction and he was not included in the DU (or PU) which initially held 170acres........now sometime after the well was in production, he recieved a copy of a declaration of that unit - apparently growing in size - which now includes 5 of his acres, and he has been getting some royalty....i just assumed that the DU had now grown to max size in the effort to HPB the surrounding (SW) land.

then chk got a permit for a the 2nd leg (NW) that went through the middle of his property, and the DU of 150ish acres included about half of his property.....initially on the completion report, it showed all the landowners included in the DU and how many acres each had (has since disappeared).....we assumed that this was also the unit from which royalties were figured.

not sure if they (chk) start small and then declare a larger unit later when they need to HBP.

seen some other gasco's use larger units right off the bat.

in lease language, "units" are not called drilling units or production units.....seems like all the verbage on units refers to a single thing.

 

RSS

© 2024   Created by Keith Mauck (Site Publisher).   Powered by

Badges  |  Report an Issue  |  Terms of Service