Replies to This Discussion

Permalink Reply by Skip Peel - Mineral Consultant on April 24, 2018 at 8:39

Click on each plat and you can print a copy.

Permalink Reply by Rock Man on April 24, 2018 at 8:45

Good to see more activity planned by major players. Thanks for posting

Permalink Reply by Skip Peel - Mineral Consultant on April 24, 2018 at 8:59

You're welcome, RM.  Next, I'd like to see a couple of COP unit well permits.

Permalink Reply by Joe Aldridge on April 24, 2018 at 9:08

Skip, They have surveyed the units/location and the road into the site. They said it will take about 6 weeks for the CC to ok the Units. As for as I'm concerned they could start preparing location. There will be no objection to the units. I'm the only one that has a problem with the Units. They should be 1280-1440 acres. COP is trying to cover as much acreage as they can to protect lease hold with operations.

Permalink Reply by Skip Peel - Mineral Consultant on April 24, 2018 at 9:12

Joe, the hearing date for both applications is 5/30.  COP does not have to wait for unit approval to apply for their well permits.

Permalink Reply by Joe Aldridge on April 24, 2018 at 9:15

I understand that. but it looks like they want to have all of there "T's Crossed and "I's dotted.

Permalink Reply by Skip Peel - Mineral Consultant on April 24, 2018 at 9:19

For the $1200 difference, COP could take twelve month as opposed to six month permits if they are overly cautious.  Either way it is chump change for COP.  Timing is largely dependent on rig availability and time for surface location construction.  Will the road be lengthy?

Permalink Reply by Joe Aldridge on April 24, 2018 at 9:22

The problem as I see it is they have +/- 100,000 acres to protect. The leases are only 3 and 3. So They need to get busy. Yes, the road is lengthy.  I don't have length but yes. 

Permalink Reply by Skip Peel - Mineral Consultant on April 24, 2018 at 9:31

I think the good news is COP can afford to bring in as many rigs as necessary without borrowing a dime if their AC acreage proves economic.  ~52 unit wells (100,000 acres/1920 acre units) in 24 months would only require about 3 rigs.  I'm thinking that if early wells are successful, there will be more than 100,000 acres to HBP.

Permalink Reply by Thomas LaSalle on July 5, 2018 at 6:54

May be somewhat off-subject and may have been addressed previously, but curious to know how far from the well perfs/fracs can an area/volume be drained?  In other words, if they set up rig in corner of 7920 x 10560' unit and drill say a 7000' lateral in middle of a zone that is 500' or more thick, how much of that unit area/volume will be 'drained' or tapped into - both in a horizontal direction and vertical direction from the perfs/fracs along a single lateral?  Leads into question of how many actual wells would have to be drilled to drain one unit in a zone 500 to 1000' thick in the AC?  Would all wells typically be drilled from a central drilling area?

Permalink Reply by Rock Man on July 5, 2018 at 7:06

Reply to Thomas @ stimulated rock volumes and drainage area

Thomas - good question as no easy answer. Stimulated rock volumes (SRV's) tied to frac's are directly tied to the geomechanical properties of the reservoir being frac'd (e.g. brittleness) and how the well is frac'd (fluid and proppant volumes, types, pressures, etc.)

And there is no algorithm that applies to every formation. And there can be variability even in the same formation in the same area.

Microseismic will probably been used in La AC trend to "see" fracture propagation and help determine SRV. Expensive but very good info when it works.

Right now, operators will be spacing their laterals far apart - probably 1000' to 1500' apart. This gives them room for a logical downsizing and infill drilling.

As an example, operators in Permian Basin and Eagle Ford - to name two horizontal plays - are placing laterals as close as 300' apart to optimize SRV and O&G recovery.

But there are also examples where operators have drilled laterals too close together and seen "frac hits' where there is overlap of SRV's from one lateral to another.

And these examples are in the Permian Basin and Eagle Ford too.

Key issues with SRV is propping the induced fracture with sand / proppant. A frac may grow outward and upward very long distances - but proppant will only be set in a much shorter part of the induced fracture. And no proppant means no contribution from that part of the reservoir.

There are no easy answers to your question but it is on every operator's mind as the plan drilling programs

Permalink Reply by Skip Peel - Mineral Consultant on July 5, 2018 at 7:15

Too many unknowns to hazard a guess at the drainage area of an AC horizontal matrix well.  State regulations prohibit a perforation any closer than 330' from a unit boundary.  It is unknown whether that distance is indeed effective in limiting drainage outside the unit boundary.  Horizontal laterals like wise can be no closer than 330' from each other.  So take the east/west dimension of  the unit and divide by 660' and you have the theoretical maximum number of wells for a single formation in a given unit.  Unit operators will drill the fewest number of wells that they think will economically recover reserves.  So spacing might be every 1000', or more.  Strictly as example,  it is possible to have the same number of wells drilled in the TMS as in the AC under the same unit footprint.  There would have to be a separate unit approved for each formation but those wells could share the same surface locations.  Trend is larger pads with multiple wells.  With units of this size there would have to be multiple surface locations.  That number would depend on the well spacing.

It is interesting that the dimensions 7920' X 10560' are a good fit for sixteen wells @ 660' spacing with each having a lateral length of approximately 7,000'.

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