- The T1/ T2 measurement based on its sensitivity to mobility can start to identify what these different phases are. Let me give you an example. On the left, I have the native-state sample. This corresponds to the black lines we saw in the previous one, and on the right, we have the re-saturated samples. These two are the same sample. This is as received, and this is after pushing some oil into it. And as you know, at the sharp T2, you have a very high T1/T2 ratio of about 10 over here, which is similar, it's not changing between the native and re-saturated. These high T1/T2 ratios are something that you do not see in conventional sample. This is something that is very, very unique to unconventionals, and we now know after isolation, and further studies, that this corresponds to the bitumen and the bound water. It doesn't change, because when you push back oil, you're not changing the bitumen or anything, which is why you see it being similar between the native state and the re-saturated state. Now this peak corresponds to some fluid, and it has a very high T1/T2 ratio, close to 4.5. Now, this is again a T1/T2 ratio that we commonly do not encounter in unconventionals. And when we put oil back in, we see that this peak grows. Look at this, I mean, the color codings goes from low intensity to high intensity. And you see this peak, which is the same as this peak, it grows. So this means that this is the same oil. You're putting back the oil in, and its signal is growing, and it's in some kind of force. And then you have this longer T2, which is not over here, and it corresponds to a much lower T1/T2 ratio. It's about 1.5, and it also has a peak. And we know that this peak corresponds to the oil in the organic pores. You can check this by taking isolated organic matter kerogen, mixing it with the oil, and you will get a T1/T2 ratio of about four to six. And this peak corresponds to the oil in the inorganic porosity. And oil in organic porosity is oil in an oil-wetting environment, which is why it has a higher T1/T2 ratio, and the oil in the inorganic porosity is the oil in a non-oil-wetting environment, or more a mixed-wetting environment, so it has a much lower T1/T2 ratio. So based on the T1/T2 and the mobility of the system, the ratios and the actual T2s, you can start to identify these different fluids. Now is this something that you can do universally, is the next question to answer, right? These are Eagle Ford Shale samples at eight different depths. And all of these correspond to native-state samples just like this on the left that we saw. So there are eight different samples. And now when I re-saturate them, this is how they look like. So I'm gonna go back and forth a couple of times so that you can see this clearly again. You will see that the bitumen and the bound water peak corresponding to the high T1/T2 ratios remains the same before and after re-saturation. And then the oil peak grows, that's the oil in the organic porosity, when you put the oil back in, and then of course you have the oil in the inorganic porosity. So you could say that universally, in the Eagle Ford Shale, and we've also done these same experiments in different kinds of shale around the US and the world, actually, that you can actually identify the different fluids, the bitumen, high T1/T2, short T2, the oil in the organic porosity and the oil in the inorganic porosity based on these T1/T2 measurements. So, therefore, we can go beyond simple T2 or T1 and get additional information. Now, we have the simple T2 distribution that I showed you at the beginning, the black being the native state, and the green being the re-saturated oil state. And of course now we know that there are these different kinds of pores, based on the 2D, the T1/T2 map that we just learned. We know that the short T2 corresponds to the bitumen in the bound water, we now know that the T2 between a millisecond and about 10 millisecond or more corresponds to oil in organic pores, and much longer T2 corresponds to T2 in inorganic pores. We are able to give this information on these 1D plots, based on the information we got from the 2D. So two-dimensional T1/T2 is vital in identifying and fluid-typing different phases in tight oil shale. Now, on the left what I have is the total re-saturated porosity. By that what I mean is, the green curve minus the black, so the native state sample, I pushed some oil in, it's just the oil quantity. So the new T2 distribution with the oil, and the one that was originally there without the oil. And that reflects the number of empty pores that we filled with the oil, right? And I've plotted against the gas-filled porosity. The gas-filled porosity is measured using a pycnometer, nitrogen pycnometry, and it fills in the pores using the gas, and there is a very good correlation between the two, which means that when you re-saturate these samples with oil you're doing a reasonably good job in filling up these empty pores. And based on the T1/T2 you can start to identify these different species that you have just found out. Now, all that we have done so far, is to do these re-saturation experiments with light oil. The oil actually used in these experiments was from the same well wherein the core was taken. But actually at a high GOR, some of the gas escaped, so it's almost dead or a low GOR of it. The question is how the these things look when you re-saturate with water. Because down-hole, the free fluids and some of the bound fluids are both oil and water. And when you bring it to the surface they both escape, so you wanna understand what happens to water. Shales around the US, and even abroad, tend to generally have high-formation salinity. Could be 100 ppk, in fact, in some parts of the Bakken I've heard of numbers beyond 200 ppk. So we de-saturated these samples with brine at 110 ppk, sodium chloride concentration. The black curve is the native-state sample, as-received measured before, and the blue one is after you push the water, or brine in fact, back into the sample. And you see that the T2 that you see of the brine in the free pores is very very long. So water, is very difficult to get the water into the organic porosity, because the organic porosity tends to be hydrophobic. It's made of organic matter. Unless you have high enough pressures and wait long enough for the water to actually slowly imbibe into these organic pores. Getting water into the inorganic pores is far easier. One major problem that you have when dealing with water, is the fact that some of these clays can take up some of this water and swells, so you start to see some of the bound water fraction increasing. But mainly the water has a much longer T2 distribution when you put it in the inorganic pores, and to remind you, some of the oil in the organic pores had a T2 between one and 10 milliseconds, which doesn't correspond to the big water peak that you see over here. So using our T1/T2, one has the possibility of identifying these different phases. Now let's go beyond tight oil shale, and see if we can get any of these applications into gas shales, which have their own importance. In gas shales of course, gas shales are much more mature than oil shale. In other words, when you have made methane gas, there is very little bitumen left in the system. So in that sense, these systems are much more simpler, because you got kerogen, you got the gas, which is in the kerogen pores, and sometimes maybe in the inorganic pores if it seeps out. And then you have bound water. You don't have bound and free light oil, you probably don't have any bitumen. So it's less complex. In some cases, there might be exceptions of course. On the left I have a gas shale sample in the irreducible state. By irreducible, I mean in the bound water state. You take a sample, it has some clay bound water in it, or you prepare it in a clay bound water state by saturating it with water, spinning it, getting all the free fluid out. And you see that the clay bound water has a T1/T2 ratio of about two. Now if you take the same sample and you push gas into it, the gas, the methane gas, which goes into even the nanopores and kerogen, has a T1/T2 ratio of 2.6. Now let me remind you, when you had very low mobility, which in other words means very high viscosity, like in bitumen, you had huge T1/T2 ratios, like about 10, 15, 20. You don't see such high T1/T2 ratios in gas shale, and the reason is that the gas molecule, even if you put it in very small pores are very mobile, which means that they will result in a low T1/T2 ratio, due to their high mobility. So, based on the T1/T2 ratio, the difference in T1/T2 ratio between the gas and the bound water is very small, it's between two and 2.6. The large differences that you see in the T1/T2 ratio between bitumen and the oil in the organic porosity, which would be between 10 and 15 and four, and oil in inorganic porosity which would be close to one, doesn't play out in the world of gas shales. So the ratios are much closer to each other, making fluid typing a little bit more challenging. And the differences are very small, the contrast is much lower, which means we need very high signal-to-noise and we need to really trust the data to separate these different species. So the kind of advantages you see of mobility-based T1/T2 maps in tight oil shale, is true to only a limited extent in gas shales. Now let's go beyond the tight oil shales and gas shales and put all the data that we have together. In other words, let's make some kind of a universal T1/T2 picture for shale at two megahertz. I choose two megahertz because it is the highest frequency that you can measure with a logging tool today, at the moment with the given technology. And on the left I have various species. I have gas, water, oil. All these are bulk. Then I have these gas, water and oil inside inorganic pores IP, or in organic pores OP, and of course I have clay bound water, and this is how they look in the T1/T2. The bulk fluids always have a T1/T2 ratio of one. And gas is very long T1/T2 ratio. Water is below gas, still ratio one and so is oil. Now when you put these fluids in the inorganic porosity, the T1/T2 ratios come down, the T2s actually come down, which is you moves from here to here, but the T1/T2 ratios also go up. It can go beyond one to 1.5 and all the way to even a little more than two. And this, as we see classically, is potentially possible in the mixed-wetting inorganic pores. Now when you wanna put the oil inside the organic porosity, and we don't have to discuss about water being in the organic porosity, because the organics are hydrophobic so we can ignore that, the oil in the inorganic porosity has much higher T1/T2 ratio, which could be of the order of three to six, and then of course you have the bound water, which has a lower T1/T2 ratio, but a shorter T2, and then of course you have the bitumen. This box over here corresponds to the region that you can see or measure with the two megahertz system. Which is like imagine the highest frequency that you can get in a logging tool. So this is what you can see. The kerogen is below this box, so you cannot see, you can see it in a laboratory measurement in a superconducting system, but you will not be able to catch it in a logging tool. So here is the bitumen with a high T1/T2 ratio, and therefore you can use something like this as a method to help you with log, so if I get T1/T2 logs, then you can use this for interpretation and identifying these different tools.