I can agree with those assessments on what constitutes an unconventional resource. The point I was trying to make was that most of what is being drilled in the Permian presently has been produced by vertical wells and mostly developed that way. Pockets within a formation of the Wolfcamp say, at least.
These formations are now being developed horizontally, which opens up a lot more area to be developed as more can be declared commercial with that technique.
Contrast that with the Bakken formation or the Eagleford. Historically, virtually none of these formations could be exploited conventionally, by vertical wells. It had to be horizontal wells with stage fracs.
I agree the water is muddied. Geologically, it makes sense to describe it the way SEG has in that a conventional trap is not present so migration is minimal.
Maybe the way that is best to describe is to say it is simply crappy rock, period.
Oh, not so crappy. Just not so good as a vertical target.
The first Bakken well I worked was in 1980, a vertical well, and pure happenstance. The Fryburg and the Duperow were the targets, but we hit a fracture set on the Billings Nose in the Bakken and drilled the rest of the well underbalanced. When all was said and done, the e-logs were such a mess (fluid/gas invasion from knocking the bottom out and killing the kick), they shot 4 ft. of perfs in the middle Bakken based on my strip log, and made 560MCF and 70 bbls of condensate a day.
But for the most part, the Bakken was only a secondary target, shows were noted in the Bakken (and Three Forks) but only the Sanish (upper Three Forks) was exploited using vertical wells as a primary target, and then only in one small area of the basin, a field near New Town, ND. Otherwise, the Bakken might be perfed if the shows were really good, in hopes of getting a little more production on the way to a P&A. Some of those wells on the Nesson Anticline made 250K barrels from the Bakken, so if the shows were good, it was worth a shot.
In the mid 80s Burlington tried to do some laterals in the Bakken, but they targeted the shale, something which generally led to a host of hole problems. The shale sloughs readily, worse in some areas than others, and since then has become the part of the formation to avoid. On longer laterals, a shale strike is a "million dollar eff-up" costing roughly that much more to sidetrack the well open hole and abandon the part that got into the shale, otherwise, the production liner has only a very slim chance of getting to bottom.
I didn't get in on any of that work in the 80s, but few of those wells reached payout and that project was abandoned. I would guess (without looking at the data) that those wells got out of target and actually opened up some of the Middle Bakken.
Then Elm Coulee was found 1998/1999, and I was in very early on that, knowing what the first two operators were looking for, I found it in a vertical well for the Company I was doing work for, and told them (1999). We made another deeper discovery in that well (infield!), but came back and twinned the well with a horizontal well with a Bakken target (2000), and that started what turned out to be a 15 year run for me, describing well over 200 miles of Bakken samples, first in Montana, later in North Dakota--especially after the wells came in up by Stanley.
As a vertical target, you're right. The odds were against you. You had a better shot at hitting on a rank wildcat in Nevada (about 1 in 75) than you did of making a vertical well in the Bakken. It was the dozen other possibilities on the way to the Deadwood that were the main objectives, and only a half dozen of those were likely. But after, with horizontal drilling, that rock didn't look so crappy after all. With a good frac, it got downright pretty.
My only Wolfcamp experience is from running Mass Spec on one well (Midland Basin), more geochemistry than geology. With that data, we were able to identify permeability boundaries and reservoir compartments, even in fairly tight rock.
With enough data like that, perhaps specific beds within the formation can be identified so those reservoir pods can be better exploited, much like the laterals we were doing in the early 90s in the Ratcliffe in the Tioga Madison Unit. There, in carbonates, the reservoir pod were bound by anhydrite, but the situation is similar in that there are discrete reservoir lenses bound by impermeable rock,just that the lenses in the TMU could be produced vertically. Still those spacings had left an unreal amount of oil and gas which could not be reached, even on an 80 acre spacing. Up here, the Red River play in Bowman County, a little in the Nisku, and other horizontal wells kept my hand in between vertical wells until the Bakken became the big kid on the block.
