Below, we see an example of a “standard” NMR T2 distribution that you might get from a typical laboratory well log calibration measurement. The shape of the distribution can tell you a lot about your reservoir, the fluids within it and the wettability of the rock.
Below is the NMR formula governing pore size distributions.
This formula is very powerful when the bulk T2 is long because the term can be ignored. The diffusion term is governed by Tau. Modern NMR instruments (such as the GeoSpec) operate at a low Tau and with that minimized, the diffusion term can be ignored as well. Once those terms are eliminated, T2 can be directly related to surface divided by the volume (or pore size).
The fluids in the rock cores can be manipulated in different ways to learn more about the pore networks, the fluids in the reservoir and the wettability of the reservoir rock.
The image below represents the water in a vial with a sharp peak on the T2 curve shifted to the right side of the curve as it has a single, high T2 value.
In the next image, we see what a typical T2 curve would look like for pores filled with water in a rock core (fully saturated with water or brine). It’s a distribution of the T2 of the free water and the water interacting with the pore walls.
When a pore is water wet, the T2 distribution becomes bimodal, as in the image below. The oil peak is on the right side of the distribution because it is in the middle of the pore away from the pore wall giving it a longer T2.
When the pore is oil wet, as we see below, the oil is interacting with the pore wall giving it a much shorter T2, and the water in the pores has a longer T2.
The question becomes, how can you tell which peak is which. Well, you can’t – at least you can’t unless you know that NMR acquires data related to hydrogen and the environment it is in. D2O, also known as heavy water, behaves like water but is invisible to an NMR instrument. It can replace the water in the core, allowing measurements to be performed only on the hydrocarbons.
In a very simplified way, you would scan the core as received. Push D2O into the core to displace the H2O. Scan the rock core again to see where the peak is on the T2 distribution. Push the reservoir oil through the rock core again and see where the peak shifted. If the peak shifts to the right (T2 increases) then the rock is water wet. If the peak shifts the left (T2 decreases) then the rock is oil wet.
It is advantageous to have a water wet reservoir as the oil recovery is significantly simplified and the recovery rates are much higher. The Green Imaging research team has focused on increasing our understanding of wettability using NMR.
More detailed information about how rock core wettability is determined by NMR can be found in this Technical Paper. Further work was captured in this Technical Paper about understanding wettability in unconventional rocks and how it can change over time.
The NMR wettability index is included in our GIT Systems Advanced software.