tell him to finish his homework and go to bed--briefly:
(can't access my email, etc)
I can see that many folks have trouble distinguishing "conventional" from "unconventional" and "tight" from "resource."
Truly there is a complete continuum here from one into the other and not always by a single simplified pathway either.
But to be a "Shale" a rock has to be a mudrock with some fissility and a grain size that is basically below the range of most normal optical microscopes to resolve. You can see the "grains," or the clay mineral particles with an electron microscope. There can be coarser grains of rock flour or silt or sand within the mudrocks - but essentially the rock fabric itself must be primarily muds.The simple Google definition from authoritarian sources is that a shale has particulate grain sizes of less than 1/256 th of a millimeter - that's a pretty tiny dimension! The cut off for the finest sands is set at 1/16 th of a millimeter - considerably coarser. (Silt lies between the clay and very fine sand dimension and so you can have coarse silt right down to very fine silt or "almost" shale. (Or mud).
Most of the Three Forks Sands and quite a bit of the Bakken sands lie in the even coarser size ranges from lower fine all the way up to upper medium sand size. That is basically from 1/8 mm up to 1/2 mm in diameter. So the finest Three Forks particle sizes - and much of the Montney Sand zones - have particle sizes some 32 times bigger than the coarsest shale particles. The average Bakken Sand perhaps 64-128 times coarser.
Since flow properties through any porous media are very sensitive to the dimensions of the narrowest pore throats and the surface properties of those same pores it is easy to see why the "reservoir" rocks get tighter the smaller the grain size becomes even where the magnitude of the porosity remains equal. This relationship is not a linear one either as the tinier the grains become the smaller the pore throats become the easier they are to block by any "fines migration" under flow conditions and the harder it is to overcome capilliary pressure requirements and surface tension or adhesion/adsorption effects.
So if one wishes to back up a bit here comparing the flow properties of the Bakken or Three Forks or Montney (with true sands in the bulk of the reservoir zones) with resource plays that are relying on flow from true shales as the reservoir component is rather like trying to compare the flow of water through a 1 metre wide pipe with that through a million tiny straws with a similar cross sectional area. It is actually worse as there is far more resistance to flow in a true shale by any comparison. A typical shale will have low nano-darcy permeability (10^-9. Or 10 raised to the power of minus nine) whereas a "conventional sand" might have from 1.0 to 100 milliDarcy permeability. Or ten raised to the power of minus one to minus three. So the tightest sand could have anything from 1 million times more permeability than a shale up to 100 million times more.
For an example the Bakken as it is being drilled horizontally around Taylorton in Southern Saskatchewan has an upper medium grained sand of about 18-21% porosity some 2-4m thick. This is a very "conventional" type of reservoir! And one that had it been discovered with vertical wells would have been quite happily drained by those simple kinds of wells. Many other parts of the Bakken throughout the basin would have responded conventionally too if the sweeter spots could have been successfully found. (And the truth is many such fields were found in the past). However much of the distribution of the Bakken does not have such singular thick or porous layers - if the Taylorton example is the "Tenderloin" - there is one heck of a lot of hamburger and stewing steak out there. What has made the difference is that fractured horizontal drilling technology has allowed much of this "Hamburger" reservoir economically productive - whereas left to produce conventionally (which these zones would be capable of doing) they would never be able to do so commercially. They would however produce! There is a Carbonate reservoir in Southern Alberta that has vertical wells in it from the 50's and 60's - and they still produce. The one has made about 25,000 barrels of oil over that 50-60 year time frame and the other slightly more. Even today if you shut them in for a year or so they return to almost original reservoir pressure! This is a tight - but entirely conventional - reservoir. (Its not wildly economic however!)
ps---for a punt that could be 'outa the park' look at my play in country where Hannibal used to raise elephants---its also carbonate, potential huge, sp beat up by weak frac charges and endless delays in replacing same---and projecting possible recovery rates of multiple mm per well!
All I am getting at is that there is a huge gulf between the reality of what the popular press (and rather lazy professionals) call shale and what is actually real shale. And I am just making the simple observation that while there may be a lot of folks happy to play fast and loose with terminology that the simple fundamental physics involved suggest great caution in making comparisons between rock and reservoir types with important reservoir properties that differ (in their natural and unfracced state) by something of six to eight orders of magnitude. Its like confusing a brine shrimp with a Blue Whale only more so...
That is the point that I was trying to make - and that is all. As you can appreciate - and any thinking man must - trying to make comparisons over such a huge gulf in the scale of basic underlying physical parameters is problematic to say the least? Of course there is a huge measure of uncertainty over where the subjective line between conventional and unconventional reservoirs is to be drawn - just as there is between conventional and simply tight reservoirs. But the gulf between sand reservoirs and true shale reservoirs simply dwarfs any such distinction - wherever it is drawn, however it is drawn and also by whomever it is drawn!
Once more this is why there is absolutely no simple correlation between the long term production behaviours of these different kinds of reservoirs - no matter how desperately hard some folks try to insist that there is. However there is great economic (and political) benefit that may be accrued by those who insist that there is. (Which is why it is so insidious a generalisation using what appears to be such a similar sounding set of descriptive terminologies).
(can't access my email, etc)
I can see that many folks have trouble distinguishing "conventional" from "unconventional" and "tight" from "resource."
Truly there is a complete continuum here from one into the other and not always by a single simplified pathway either.
But to be a "Shale" a rock has to be a mudrock with some fissility and a grain size that is basically below the range of most normal optical microscopes to resolve. You can see the "grains," or the clay mineral particles with an electron microscope. There can be coarser grains of rock flour or silt or sand within the mudrocks - but essentially the rock fabric itself must be primarily muds.The simple Google definition from authoritarian sources is that a shale has particulate grain sizes of less than 1/256 th of a millimeter - that's a pretty tiny dimension! The cut off for the finest sands is set at 1/16 th of a millimeter - considerably coarser. (Silt lies between the clay and very fine sand dimension and so you can have coarse silt right down to very fine silt or "almost" shale. (Or mud).
Most of the Three Forks Sands and quite a bit of the Bakken sands lie in the even coarser size ranges from lower fine all the way up to upper medium sand size. That is basically from 1/8 mm up to 1/2 mm in diameter. So the finest Three Forks particle sizes - and much of the Montney Sand zones - have particle sizes some 32 times bigger than the coarsest shale particles. The average Bakken Sand perhaps 64-128 times coarser.
Since flow properties through any porous media are very sensitive to the dimensions of the narrowest pore throats and the surface properties of those same pores it is easy to see why the "reservoir" rocks get tighter the smaller the grain size becomes even where the magnitude of the porosity remains equal. This relationship is not a linear one either as the tinier the grains become the smaller the pore throats become the easier they are to block by any "fines migration" under flow conditions and the harder it is to overcome capilliary pressure requirements and surface tension or adhesion/adsorption effects.
So if one wishes to back up a bit here comparing the flow properties of the Bakken or Three Forks or Montney (with true sands in the bulk of the reservoir zones) with resource plays that are relying on flow from true shales as the reservoir component is rather like trying to compare the flow of water through a 1 metre wide pipe with that through a million tiny straws with a similar cross sectional area. It is actually worse as there is far more resistance to flow in a true shale by any comparison. A typical shale will have low nano-darcy permeability (10^-9. Or 10 raised to the power of minus nine) whereas a "conventional sand" might have from 1.0 to 100 milliDarcy permeability. Or ten raised to the power of minus one to minus three. So the tightest sand could have anything from 1 million times more permeability than a shale up to 100 million times more.
For an example the Bakken as it is being drilled horizontally around Taylorton in Southern Saskatchewan has an upper medium grained sand of about 18-21% porosity some 2-4m thick. This is a very "conventional" type of reservoir! And one that had it been discovered with vertical wells would have been quite happily drained by those simple kinds of wells. Many other parts of the Bakken throughout the basin would have responded conventionally too if the sweeter spots could have been successfully found. (And the truth is many such fields were found in the past). However much of the distribution of the Bakken does not have such singular thick or porous layers - if the Taylorton example is the "Tenderloin" - there is one heck of a lot of hamburger and stewing steak out there. What has made the difference is that fractured horizontal drilling technology has allowed much of this "Hamburger" reservoir economically productive - whereas left to produce conventionally (which these zones would be capable of doing) they would never be able to do so commercially. They would however produce! There is a Carbonate reservoir in Southern Alberta that has vertical wells in it from the 50's and 60's - and they still produce. The one has made about 25,000 barrels of oil over that 50-60 year time frame and the other slightly more. Even today if you shut them in for a year or so they return to almost original reservoir pressure! This is a tight - but entirely conventional - reservoir. (Its not wildly economic however!)
ps---for a punt that could be 'outa the park' look at my play in country where Hannibal used to raise elephants---its also carbonate, potential huge, sp beat up by weak frac charges and endless delays in replacing same---and projecting possible recovery rates of multiple mm per well!
All I am getting at is that there is a huge gulf between the reality of what the popular press (and rather lazy professionals) call shale and what is actually real shale. And I am just making the simple observation that while there may be a lot of folks happy to play fast and loose with terminology that the simple fundamental physics involved suggest great caution in making comparisons between rock and reservoir types with important reservoir properties that differ (in their natural and unfracced state) by something of six to eight orders of magnitude. Its like confusing a brine shrimp with a Blue Whale only more so...
That is the point that I was trying to make - and that is all. As you can appreciate - and any thinking man must - trying to make comparisons over such a huge gulf in the scale of basic underlying physical parameters is problematic to say the least? Of course there is a huge measure of uncertainty over where the subjective line between conventional and unconventional reservoirs is to be drawn - just as there is between conventional and simply tight reservoirs. But the gulf between sand reservoirs and true shale reservoirs simply dwarfs any such distinction - wherever it is drawn, however it is drawn and also by whomever it is drawn!
Once more this is why there is absolutely no simple correlation between the long term production behaviours of these different kinds of reservoirs - no matter how desperately hard some folks try to insist that there is. However there is great economic (and political) benefit that may be accrued by those who insist that there is. (Which is why it is so insidious a generalisation using what appears to be such a similar sounding set of descriptive terminologies).