6 units in SW Mount Common Church Field, 7 units in Freeland Field and 6 units in NW Jackson Field.
These units seem to indicate that the AC is seriously real. Of course, the story will be told when we see the IPs.
The formation of units is not necessarily an indication of potential success. I can show plenty of Haynesville Shale drilling units that were formed in groups, like this, that were never drilled owing to poor well results in that area. A drilling unit is effective indefinitely, whether drilled or not, and comes with no requirement to drill one well. The advantage of forming units ahead of drilling wells is to hold leases. Any producing well regardless of whether it is economic or not, drilled in an approved unit holds all the leases covered by that unit. The best recent example of this is the TMS. Those units were also large and a good many got a well that was productive, not necessarily economic. This of course created an opportunity for Australis to acquire TMS development rights on the cheap after the major players had moved on. Whether all these units will be drilled depends on well results as Jesse points out. If results are not supportive of continuing investment, many of the units will go un-drilled. The jury is still out and will be for some time.
I hope we don't have to wait that long. I'd like to see COP bring in a couple of rigs and commit to a half dozen or so initial wells.
That would be nice, but production decline rates over time will be a key point as to the economics of this play.
I agree with Rock Man. You don’t want 6 wells exhibiting the same decline as the EOG well.
So, what will you be looking for, IP 180, or longer? How long did previous LA horizontal AC wells, drilled to intersect natural fracture networks, last before the decline accelerated?
Great question - I haven't had time to do analysis on historical La AC hz natural fracture plays and declines - so cannot answer that yet. But based on similar Tx wells, the decline profiles in these types of wells varies depends on natural fracture intensity and associated O&G (vs water) charge.
That being said, I would want a MINIMUM of 6 FULL months of production data. And then every additional month helps a lot as to establishing legit decline trends.
Of course, one has to also consider other factors when looking at post frac well performance - including but not limited to the issues noted in my post on EOG well. Frac intensity, proppant and fluid concentrations, lateral length, in target consistency, etc. all impact post frac performance.
And I would then tie in the matrix AC data from nearby vertical wells to try to relate post frac well performance to matrix quality.
Two years from now, we will have (ideally) several wells spread across the area to look at as to results - and I predict we will have a wide range of results to consider (poor to very good).
Thanks, Rock Man. I think I speak for most of us here when I say, we don't want to wait that long! :-)
Agree - but unlike conventional reservoirs / wells where you get a "good or bad" soon after completion, unconventional plays require a major PATIENCE trait that is tough to do (but necessary).
Do you know what the lateral length is on the Mckowen well.
It is permitted to be 2000'.