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  3. T1-T2 experiments on oil resaturated samples Vycor porous glass and Eagle Ford shale

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- [Instructor] The next stage is sample preparation. We were interested in understanding unconventional shape. This could be gaseous, this could be tight oil shape. And what these samples are, these are very tight samples and when you have them at the surface, they are taken from a high pressure environment to the surface where you have atmospheric pressure. There's a lot of blow-off. So some of the producible fluid is all gone so you have to get it back into the sample and get it as close to an environment as possible to the formation so that you can study. This is the setup we have at Slumber-sheet-old research. It can go to several thousand PSI in pressure. We have the system connected to a vacuum pump to suck vacuum in the samples and this is important because oxygen in the atmosphere is paramagnetic. So you don't want anything in our sample that will go into the core because it can cause additional relaxation. This system is made of fiberglass so it can actually be put inside a magnet, an NMR magnet so there's no metallic parts or magnetic parts. So the first step is to evacuate the samples get out all the oxygen using the pump. And the next step is to push the fluid into it at high pressures. It could be 2000 PSI or more and leave it at that pressure for more than 48 hours as this fluid is getting into sample when you leave it at high pressure for a long period of time now this is something we do and we start with some examples of results based on model systems. When I say a model system, I mean Vycor porous glass. Its a silicon oxide glass. It has pore size of four nanometers which is why it was chosen. The reason being four nanometers is very small pore size so its comparable to some of the smallest pores you will see in shape but this is not a Shale sample. It is a porous glass sample so the pores are not made of kerogen or organic matter. The pores are made of glassy silicon oxide which is very, very hydrophilic. It loves water. This is being saturated by two fluids. One is water and the other being Dodecane or an oil. I have the results of water here and I have the results of Dodecane here. Let's focus on the two dimensional plots, the T1 over T2 on the left and the right. This is for water and this is for oil. Now like I mentioned this porous media really, really loves water. It is very hydrophilic in nature. So when you put water into it, because its hydrophilic and water wetting, the water is really immobile inside this fluid. So it is water wetting so it has, it sticks, water sticks to the surface. That's the way to think about it. All along the other hand because its very weakly oil wetting, it doesn't really stick to the surface so its much more mobile. As I said, the NMR T1/T2 measurement is a reflection of mobility. Now the water being less mobile, has a T1/T2 ratio of 25.95. The oil on the other hand in the same pore, being more mobile has a T1/T2 ratio of two. So that is an order of magnitude. Difference in the T1/T2 ratio between the water and the oil because of their mobility inside these small pores in Vycor. This is a classic example of how T1/T2 can be a reflection of mobility and we're gonna take this same idea of being sensitive to mobility into applications for shape. How do we use T1/T2 and its sensitivity to mobility in Shale. Let's go to the world of Shales which is what is the most important thing for us. This is a classic slide of a T2 distribution. The black is a T2 distribution of a native state sample This is an Eagle Ford shale. By native state what I mean which is a shale which has been unpreserved. It has been taken from downhole not under pressure, it is not preserved. Some of the producible fluids are gone because of change in pressure. And without any cleaning, without any additional chemical treatment or anything, it is measured as a seat. That's the black plot. And you'll see there's some kind of T2 and then there's some T2 peaks etcetera. The same shale now I push back oil into it and I measure it again and I get the green. Now this green minus black is the additional porosity that I have put into this shale. Now you see that at short T2s there is no change and at long T2s there are some pores that we're filling. So what do these correspond to? Based on simple one dimensional experiments we cannot say. So this is the same thing that I've done in the previous slide but now I show you in 10 different depths. The black is the native state sample and the green is the same after pushing back oil. So native state and resaturated. When I resaturate it, I have some additional porosity. That's the empty pores that are there in the native state that I am filling again so there's some empty porosity. But the identity of these different phases and what these empty porosities correspond to, is it organic pores, is it inorganic pores, if something you cannot say based on simple one-dimensional distributions. You need more information. You need another dimension. You need additional analysis to enable you to find out these different details. So one such way to do this as we have set up ourselves is that T1/T2 measure. What can it do?