D, They haven't announced the findings from IW#2 clearly, as in...

D,

They haven't announced the findings from IW#2 clearly, as in what's the gross & net thickness of the HRZ unless they expect everyone to dig up Dec 2015 ASX updates !!

So, the question is what does this upper & lower perf intervals refer to 'depth' wise ?

At IW#1, the 'Transition' zone started from 10970-11075 ft.

HRZ was cored from 11075-11165 ft (90 ft).

This gives them apprx 195ft gross thickness (ie 10970 - 11165 ft), with 180.5 ft net at IW#1.

Detailed analysis for the cored interval gave them the average porosity, permeability, ToC, matrix data, geomech's etc and wireline logs gave them a 70% oil saturation etc etc. All great for IW#1.

Since IW#2 is a few metres away form the pilot well & assuming no hidden surprises, they should have got a similar result. Still that doesn't answer the question, i.e,

where exactly is the first test interval planned (ie from 10xxx to 11xxx'), how thick is this (xx or xxx ft), followed by the second, from the total gross (xx or xxx ft) HRZ Shale interval intersected/logged/cored next doors ? Hopefully, post testing all will b revealed.

As for the uncertainities et al, they r part & parcel.

Above-surface:

One usually prepares for all possible mechancial issues during their logistics planning, ie proppant volume, viscosity, Water on site, Storage Tanks, separator, choke manifold, EMR pressure gauges, Brine, N2, diesel, hot oiler, coil tubing units, ice plug removal etc etc.

Sub-surface:

If the stress pattern or wellbore breakout profile is good then they can design the fracjob with a relevant mix of the proppant/fluid to create additional or well connected pathways for the reservoir fluid to seep out.

If they think the rock is too hard due to the high siliceous matrix in the Shale, poro/perm of the interval, then a higher proportion of proppant etc can b pumped to create better pathways or network of fractures.
That is entirely up to their Frac Team to work out. Hence, the need to keep the two test zones separate to suss out which one flows better firstup (upper one or the lower one).

Once they get some sort of returns from the flowback (post cleanup), then they have a chance to take representative fluid samples of gas or condensate through the separator & calculate the GOR, CGR, density in API, any water etc etc.  

They mentioned at IW#1 about high permeable zones in couple of core samples, so perhaps that's perhaps where 'flows like conventional' theory fits in (alongwith the porosity & pressure gradient).

Still it's a Shale they r frac'ing, not a conventional Sandstone reservoir, so the answer is still 'Unknown'.

To summarise, flowrates from overpressured oil saturated thick Shales with nanodarcy(?) permeability depends on the mix/ integrity/blend of the frac fluid slurry, stress regime, reservoir pressure gradient & completion practices. Will b interesting to note how this story unfolds in Alaska.  

Have a good wk'end all.