My understanding of geology comes from being a production engineer, so take what I say under caution. GGGAL might have more to say on this. Here is my understanding which I think is much the same as yours.
In order to get a conventional accumulation of hydrocarbon, you first need a source rock (Shale) in which the organic material (kerogen) is heated to form oil, wet gas or dry gas. The heat is caused by the burial of the sediments. The higher the temperature the more likely you are to get gas. So the process is kerogen to bitumen (oil sands) to black oil to wet gas (condensate plus gas) to dry gas as heat is applied. The temperatures at which you start to turn kerogen into black oil is surprising low at 60 c to 120 C. Above that you start getting gas. The hydrocarbons then migrate and may get trapped in a porous rock such as sandstone (a reservoir rock) or it may come to the surface as oil seeps at Norman Wells.
The IFR Summit well is a conventional reservoir. That well tapped into a permeable reservoir (Arnica) which got its hydrocarbons from the Canol. The Canol at the IFR site is much deeper (+700 metres) than the Canol in the northern area and as a result, the kerogen in the Canol at the IFR well was cooked into wet gas rather than oil. Hence the test of 20 MMcfd and 6,000 bopd of condensate (53 API). The Norman Wells oil is 43 API. Condensate is vapour in the reservoir and condenses out at surface temperatures. It looks like white gas used in the coleman stoves. (I think IFR would agree with this interpretation as the most recent IFR presentation has a map showing that Summit is in the wet gas window)
Shale is much different than conventional reservoirs. There is no migration to a permeable reservoir rock. The oil is generated in the shale and stays there. The source and the reservoir are the same. While the chances of getting all the right conditions for a conventional deposit are slim, the chances of finding shale is very high as shale is the most common sedimentary rock in the world. In addition to finding shale you need lots of organic content (TOC) and the right amount of heat. The TOC in the IFR wells is lower than the north. (see IFR presentation).
This is why the industry is so excitemed over shale. It is relatively easy to find and covers large areas. Conventional reservoirs were very difficult to find and covered small areas. The advantage of conventional was that they had high permeabilities while shale has almost no permeability. Hence the use of horizontal wells with up to 30 frac per well.
The IFR well is located in an area that does appear to be a drillers nightmare. Looking at the IFR maps they show a lot of fault zones. It is possible that the oil generated in the Canol in the IFR area could have been lost to migration. I haven't seen the logs for the Canol in these wells. I beleive that GGGAL has looked at them. However in the north, the Canol seems to be full of oil. The logs are available on the MGM website and Husky has core. It doesn't appear that they have the same drilling problems in the north. The two Husky wells drilled last year and the MGM Windy Island well encountered no problems.
So we want fracturing of the Canol to improve production rates, but no so much that it will allow the oil to escape to the surface. The first discovery well in Norman Wells drillled in 1920 seems to have these conditions. When the drill bit hit the Canol at 220 metres it blew oil 20 metres in the air. So it appear the Canol was fractured as shales don't have blow outs. It also appears that the fracturing was not so great as to allow the pressure to escape the Canol.
I guess this is why the testing is so important. They are going to find a thick section of the Canol and it is going to be full of oil That I am pretty sure of. Will the Canol produce oil? I think so, but don't know.