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  3. Interpretation: Non-Reservoir Rocks

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- [Dr. Merkel] What I wanna do is switch gears a little bit, because what we were just talking about was the reservoir component. Now I wanna talk about the non-reservoir component, because from this, we can determine by looking at the non-reservoir components, we can look a little bit at what kind of saturation models we can use. So what we get is just look at the shale components, and as you saw from the very first, guess that's second or third slide where we show all the logs for the lower Green River. There's mostly shale, and with these fluvial sands moving in now. But if you take the water that you calculate in the shale component, and plot that on the y-axis, and say that the only thing that's conducted in there is the water, and you look at the MSFL and plot those data, you can see that you get a nice cluster of data where you can calculate again what the resistivity of the clay-bound water is at 100% up here, and you can calculate what the M is for the clay component. I normally use this just to calculate what the clay resistivity is. The interesting thing is, I'd have looked at hundreds and hundreds of these kinds of plots in the Rocky Mountains and also in Texas, and see this exact same thing. And the interesting thing is that all these things show me that I have a slope of minus one which is minus one over m, which means m is minus one, or the clay component, which is most peculiar, because two reasons. One is, this says that it acts like a fracture, number one. And number two is, most saturation models will not accept an m for the clay component. Most shaley sand models will not accept a clay component m different than the m that's used for reservoir component. But the other interesting thing is, if I calculate what the clay-bound water is from the NMR, And we've done this in a number of wells, we have both the dielectric on this, on the screen on the left in purple, and we get the clay-bound component from the NMR over on the right hand screen, and this is over the exact same mineral by the way, in the same well. You get the same kind of relationship. And it gets an m of minus one. The other really interesting thing is, contrary to my original thought on the clay salinities, is all these salinities come out to be about 4,000 ppm, which was a real surprise to me, because normally we'd consider that clay-bound water from having salinity in the 60's and 70's and 80,000 ppm, but I never see that. It's always around 4,000 ppm. So what this did is eliminated the number of shaley sand models that can accept these kinds of relationships, and then calculate what oil in place is. One of the other things that I did is, from my days at the Marathon Research Center, I was able to compile a whole bunch of data that gives me the clay vine run experiments, dry, and where you dry clay and completely saturated clay. I can calculate what the clay bound, from the clay volume on the y-axis, versus the clay-bound water on the x-axis, and this ends up being a linear relationship, with smectite being in blue, illite in green, chlorite in red, and kaolinite in brown. And the slope of these lives gives me the relationship, it's up here in the top. This is clay component, it's this constant, times the volume of clay-bound water. So, you can use this one of two ways. You can say okay, if I can measure clay-bound water, which I can do with a dielectric tool, or the NMR tool, then I can calculate the volume of clay, just by this relationship, if I know the type of clay it is. The other thing we can do is say we have XRD data, then we can calculate what the volume of clay is, from each clay mineral, then if you use the XRD in a volume percent rather than a weight percent, then you can calculate what the clay-bound water is. And we'll see in the examples, which I'm running out of time, so I'm gonna move ahead to do this. At any rate, this is not in that paper in October, but I'll show it to you. This is the Niobrara formation, is some of the Upper Cretaceous formation, shale formation, that's pervasive through Colorado, Wyoming, North Dakota, South Dakota, and Montana, and in the model that I had, if you calculate the volume of clay, and knew what clay it was, I can calculate the clay-bound water. And look at this, when you calculate the clay-bound water, knowing what the volume of clay is, the slope of this thing is minus one. It's just absolutely remarkable. And again, why I use this, is I can take this intercept in the shaley sand model and get you the resistivity of the clay-bound water model, or I can extrapolate this thing up to where it intercepts this axis, and this'll give me the clay resistivity.

- [Dr. Merkel] What I wanna do is switch gears a little bit, because what we were just talking about was the reservoir component. Now I wanna talk about the non-reservoir component, because from this, we can determine by looking at the non-reservoir components, we can look a little bit at what kind of saturation models we can use. So what we get is just look at the shale components, and as you saw from the very first, guess that's second or third slide where we show all the logs for the lower Green River. There's mostly shale, and with these fluvial sands moving in now. But if you take the water that you calculate in the shale component, and plot that on the y-axis, and say that the only thing that's conducted in there is the water, and you look at the MSFL and plot those data, you can see that you get a nice cluster of data where you can calculate again what the resistivity of the clay-bound water is at 100% up here, and you can calculate what the M is for the clay component. I normally use this just to calculate what the clay resistivity is. The interesting thing is, I'd have looked at hundreds and hundreds of these kinds of plots in the Rocky Mountains and also in Texas, and see this exact same thing. And the interesting thing is that all these things show me that I have a slope of minus one which is minus one over m, which means m is minus one, or the clay component, which is most peculiar, because two reasons. One is, this says that it acts like a fracture, number one. And number two is, most saturation models will not accept an m for the clay component. Most shaley sand models will not accept a clay component m different than the m that's used for reservoir component. But the other interesting thing is, if I calculate what the clay-bound water is from the NMR, And we've done this in a number of wells, we have both the dielectric on this, on the screen on the left in purple, and we get the clay-bound component from the NMR over on the right hand screen, and this is over the exact same mineral by the way, in the same well. You get the same kind of relationship. And it gets an m of minus one. The other really interesting thing is, contrary to my original thought on the clay salinities, is all these salinities come out to be about 4,000 ppm, which was a real surprise to me, because normally we'd consider that clay-bound water from having salinity in the 60's and 70's and 80,000 ppm, but I never see that. It's always around 4,000 ppm. So what this did is eliminated the number of shaley sand models that can accept these kinds of relationships, and then calculate what oil in place is. One of the other things that I did is, from my days at the Marathon Research Center, I was able to compile a whole bunch of data that gives me the clay vine run experiments, dry, and where you dry clay and completely saturated clay. I can calculate what the clay bound, from the clay volume on the y-axis, versus the clay-bound water on the x-axis, and this ends up being a linear relationship, with smectite being in blue, illite in green, chlorite in red, and kaolinite in brown. And the slope of these lives gives me the relationship, it's up here in the top. This is clay component, it's this constant, times the volume of clay-bound water. So, you can use this one of two ways. You can say okay, if I can measure clay-bound water, which I can do with a dielectric tool, or the NMR tool, then I can calculate the volume of clay, just by this relationship, if I know the type of clay it is. The other thing we can do is say we have XRD data, then we can calculate what the volume of clay is, from each clay mineral, then if you use the XRD in a volume percent rather than a weight percent, then you can calculate what the clay-bound water is. And we'll see in the examples, which I'm running out of time, so I'm gonna move ahead to do this. At any rate, this is not in that paper in October, but I'll show it to you. This is the Niobrara formation, is some of the Upper Cretaceous formation, shale formation, that's pervasive through Colorado, Wyoming, North Dakota, South Dakota, and Montana, and in the model that I had, if you calculate the volume of clay, and knew what clay it was, I can calculate the clay-bound water. And look at this, when you calculate the clay-bound water, knowing what the volume of clay is, the slope of this thing is minus one. It's just absolutely remarkable. And again, why I use this, is I can take this intercept in the shaley sand model and get you the resistivity of the clay-bound water model, or I can extrapolate this thing up to where it intercepts this axis, and this'll give me the clay resistivity.