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What is a darcy?

Permeability is the capacity of a porous material to transmit fluids. The SI unit of permeability is m2 (area) but the units adopted by the petroleum industry have been named after Henry Darcy, who derived Darcy's law. The darcy is a confusing jumble of units which combines standardized SI units from laboratory tests. By definition, a material of 1 darcy permits a flow of 1 cm3/s of a fluid with viscosity 1 cP (1 mPa.s) under a pressure gradient of 1 atm/cm across an area of 1 cm2.

Apart from having obscure units with an empirical origin, permeability can be an incredibly variable quantity. It can be as low as 10-9 D for tight gas reservoirs and shale, to 101 D for unconsolidated reservoirs. Just as electrical resistivity, values are plotted on a logarithmic scale. Many factors such as rock type, pore size, shape and connectedness and can affect fluid transport over volume scales from millimetres to kilometres. For a nice commentary on permeability in connection to continental scale near-surface hydrolithologic categories, read Anne Jefferson's (@highlyanne's) new post on Highly Allochthonuous.

Okay then, with that said, what is the upscaled permeability of the cube of rock shown here? In other words, if you only had to find one number to describe the permeability of this sample, what would it be? I'll pause for a moment while you grab your calculator... Okay, got an answer? What is it?

If you are like most people, you would define the upscaled permeability by computing the arithmetic average by adding the three contributing zones, weighted by their proportion:

Even if you didn't do this calculation rigorously, most people would look at the three values shown (1.1 D, 0.1 D, and 1.1 D) with respect to their relative proportions, and say that the upscaled permeability must be somewhere between the lowest value and the highest value. You might even speculate, since there is 9 times more of the high perm rock than the low perm rock, that the average is just a little less than 1.1 D.

If you got 1.0 D for your answer, you are only half right. Sorry if you feel like I set you up, but this isn't the final answer.

Here's why it's only half of the solution: 1.0 D is the horizontal permeability of the sample. In fact, upscaling permeability is meaningless unless a direction is coupled with it. For this example, 1 cm3 of water (at 1 cP) would take one second to travel through this rock under horizontal pressure gradient of one atmosphere. That same 1 cm3 of water would take 85% longer to travel through our sample under a vertical pressure gradient of the same magnitude. And obviously if there is no pressure gradient, there is no flow.

To correctly calculate the vertical permeability, the harmonic, not arithmetic, mean should be used:

Upscaling is routinely done in geoscience and reservoir characterization, because we have to compare measurements at different scales. It is important for geoscientists and engineers to be aware of the pitfalls of averaging and upscaling, and understand when to choose the correct formula. Because even the right answer could be the wrong answer with upscaling. If you were surprised by this little tutorial, go test a friend or colleauge. Even simple concepts are worth refreshing from time to time. See if you can get them thinking about the differences between horizontal and vertical permeability, and the impacts of arithmetic and harmonic averaging (upscaling) on the work that you do. Please leave a message in the comments if you are able to stump or surprise your peers.

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Reader Comments (3)

I was only half-right :(

It is interesting how we often use horizontal permeability exclusively, since the wellbore is assumed “perpendicular” to bedding - but with with laminated sands, deviated wells and limited entry perfs it is more likely we would be ‘limiting’ our permeability somewhat by having a combination of vertical and horizontal perms to contend with. Maybe this is also part of the reason why some of our zones don’t flow on perforation?

Thanks for the thought-provoking puzzle. I’ll keep this in mind for any upscaling discussions I happen to be a part of.

January 28, 2011 | Unregistered CommenterAndrea

Wonderful comment. Let me build on your response by tweaking our example. What is the upscaled permeability if our tight streak now has a value of 0.01 D? Going through the arithmetic formula we get: Kxy = 0.991 D, whereas the harmonic formula yields Kz = 0.092 D. In other words, it would take one second for one millilitre of water to go horizontally through our sample, but it would take 11 seconds (!) to go vertically. The tight streak doesn't really have an impact on horizontal flow but it dramatically impedes vertical flow. It is fascinating to think about the implications of this, in terms of drilling perpendicular vs. oblique to bedding, oriented perfs, etc. It would be interesting to learn if there is a preferred way to examine permeability anisotropy empirically. Are cores and sidewall cores our only hope?

January 28, 2011 | Unregistered Commenterevan

I think one trap many people fall into is to become overly focused on permeability estimation. I don't want to rain on the parade, but there are a variety ways to calculate permeability and one thing they all have in common is being wrong. Permeability is an over simplified approach to describe the reservoir's ability to produce; I think we can all agree reservoir rocks are anything but simple. There is nothing wrong with that because petroleum engineering is NOT an exact science (even though many petroleum engineering methods are). A permeability calculation is only as good as its calibration to a production rate. And let's be honest, that's what we really care about because that is our measure of cash flow and therefore value. So the next time you see someone present you with an intimidating approach to a permeability calculation, don't be afraid to ask them, "How well does it match your production?" If there is no production, then it's just a guess, hopefully a well educated one.

January 29, 2011 | Unregistered Commenterj

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