Just took a close look at the TriOil September presentation and the type log on page 9. To my way of thinking they have a sand zone about 1.3m thick with an average of 15% porosity. This clean sand spike is underlain by a zone perhaps 4.5m thick that has small lenticular very fine grained sand pockets distributed within shale interbeds that increase in a percentage fashion from about 20-30% of the bulk rock volume near the top to about 50-60% at the base. (This rapid drop off in sand content - and corresponding increase in shale is ably demonstrated by the rapidly dropping resistivity log tail on the furthest right curve - as well as the rapidly diverging neutron and density porosity curves on the left of centre track - which basically mirrors the resistivity story. This is then underlain by really silty sandy shaly material of practically no consequence for the remaining 13.5m to the base of the noted Cardium Sand as drawn on the cartoon.
This excellent 1.3m clean and porous sand is the key to the good IP and the then sustained fair average flow over the first month. The underlying lenticular and shaly sands to sandy shales also help with that excellent IP - but are most responsible for the subsequent inferred rapid decline rate as these sands would have very limited lateral permeability once the fractures have drained all the adjacent oil saturated sand lenses within decimetres of the reservoir opened up by the fracture treatment.
While the clean thin 1.3-1.5m upper sand may have excellent reservoir quality - and a likely 20-25% recovery factor - the underlying 4-5m flaser bedded shaly sands would be lucky to achieve anything greater than a 3-5% recovery factor. Those underlying shaly sands must be reduced in effect for the Net to Gross ratio of sand to shale and also by the average sand porosity values of these laterally poorly connected pockets? Assume an average net sand thickness of 50% and porosity in the 12% range - perhaps 15% in parts? - that gives maybe an extra 2.0m to 2.5m of net sand to add to the overlying permeability superhighway.
To calculate theoretical recovery per unit area one would have to split the reservoir into these two discret layers and sum the recoverable reserves in them separately with appropriate calculated Recovery Factors applied to each. That thin high quality sand is going to deplete fast as the pressure drawdown front moves rapidly away from the well bore and fractures. The lower permeability stuff underneath will deplete much more slowly as the oil feeds up into the higher perm layer through fractures or laterally where there are induced fractures that allow such migration. But typically these flaser bedded shaly sands have very little effective natural vertical permeability of their own - and not much better horizontal permeability either.
For comparison the best Bakken wells at Taylorton are draining a 2.5m thick, clean, high permeability 15% porosity sand which is underlain by about 2.5-3.0m of interbedded but flat lying and more laterally permeable (not lensed) shaly sands of much poorer reservoir quality. So on a direct comparison basis the Taylorton Bakken wells have more actual reservoir to play with - almost double the Net Pay thickness? But of course the Bakken produces at a 30-60% water cut while the Cardium is virtually water free.