The other item of interest here and I believe of high importance at this time is the description on how natural gases flow through the extremely low permeability rock such as in unconventionals.
The way any gas flows from the reservoir rock to the wellbore for production is due to pressure drops. Gas easily does this as its viscosity is so low, as compared to a liquid like oil or water. (Viscosity problems are the reason I continue to say that the numbers of horizons that contain movable hydrocarbon liquids in situ within unconventionals are limited).
However, some of these unconventional rocks have such low permeability that one can produce a well for years and still find untapped, high pressure gas just a few hundred yards away. This is not predictable and is still not explained by Darcy's law with ultra-low permeability.
What is needed is more effort to the description of gas flow in these types of rocks. One complicating factor that has been found is that fluid flow is traditionally been estimated in conventional rocks which are sands and carbonates. Unconventionals are more in shales that contain much finer components, and harder to describe.
Geology invariably controls things, as @Smokin Joe will attest.
In the wells I did in the Bakken, what is commonly assumed to be dolomite is often a mixture of hydraulically similar grains with common sedimentological characteristics, but not all dolomite. Silt, fine sand, some clay minerals and organics, and even pelletal limestone have been observed in the wells I worked (samples I personally described). That makes the game much more complex, as there are not only the lattice distortions in dolomitization to be taken into effect but the variety of grain sizes and shapes in materials of differing density which settled in the depositional environment there, along with localized variation in the energy of that environment.
While wells in a general area may share similar sedimentological character, the rocks can and do vary. That is often seen in the relative durability of the tools in the downhole environment, where on some wells the entire run can be done with two or even one mud motor and bit, in others it has taken as many as eight mud motors and bits, all needing to be replaced because of the relative abrasiveness of the silica replaced dolomite and overgrown very fine sand in the formation.
That all means differing pore geometries, and affects the likelihood of natural fracturing in the formation (and whether those are healed or not), as well as the primary porosity and probability of secondary solution porosity.
It isn't a simple system, and it isn't any more layer cake than walking along and looking down at the ground will have the same material underfoot, even at a beach.
But I still think pore throat pressure drops are key to permeability for liquids in a multiphasic environment.
I saw some research being done on bubble points up in Regina years ago where they were trying to determine how to prevent pore throat choking by gas bubbles. Pressure maintenance may be the only viable solution to having areas of the reservoir effectively sealed off by gas bubbles, and pore geometry is key to getting the right fluids to flow even if the pore throats don't become blocked. (Water can flow around oil in a larger intergranular or solution space, leaving the oil trapped in the rock.)
It is a complex problem, and only looking at the rock in thin section or under SEM will get the answers, and that takes core samples.
(Try to get that on the AFE).
