- [Sarita] In this slide here, I am showing the results of the porosity of the sand fraction computed using the Thomas Steiber method. So here I'm also showing how they compare with the core porosity. So here you see the gamma ray on the left, the resistivity track in the second and the third is the density. On the fourth track, I show the porosity curve, with the core porosity overlaid on it. You can see there is a reasonable match with the core porosity. Also if you see in the massive bed which is where I have used the Thomas-Steiber approach you can also see that there is a good match with the log porosity and the core porosity. Another thing I wanted to just share about the Thomas-Steiber approach is that since it is a approach that we use for laminated sand, our approach for laminated stand, should, because of the assumptions that we use that the properties of the sand in the massive beds, and in the thin beds, are similar. So that's why the Thomas-Steiber approach should give you a result same as the conventional approach in a massive bed. So what I have not shown here, but what I did was, I also calculated the porosity using conventional equation for the density log and put that here and matched it with the Thomas-Steiber. And I saw that the Thomas-Steiber boils down to the conventional as you go to the massive beds. Which is a very good test that your assumption, that your properties for your massive beds and your thinly laminated sands are same. Now, we show here the core porosity statistics. Again, all this work, what I'm trying to do here is trying to strengthen my porosity computation. I will go step by step. I will first develop my confidence in my porosity and then I will develop my confidence in the net-to-gross, and then when I have both porosity and net-to-growth taken care of, then I will try to strengthen my confidence in the saturation. And this way I can have a robust interpretation where I have taken porosity, saturation and net-to-gross and tackled them separately. But at the same time I am also observing the effects of, one on the other. Here I am showing the histogram for the core porosity. So what I show here is for the A1 zone and on the right you see for the massive bed. So you'll see that the average porosity 32% for the core plugs taken in the thinly laminated zones and the average porosity in the massive beds is 31%. Which tells you that even though these are so thinly laminated sands that ranges in thickness of like centimeters, these have similar porosities to the massive beds. Also, we don't show permeability here but I have seen those in the major beds, the permeability of these thin beds is also very high. Which tells you that they should not be ignored because they can contribute to your flow. What I show here in the histogram is, I show a bunch of wells where I have compared the rare shows of porosity using Thomas-Steiber and the blue shows the porosity using conventional. You can see that the porosity in the blue is higher and it will be very funny to say that how come in conventional approach you have a porosity that is higher than what you should, we should not expect that. We should expect Thomas-Steiber giving you better porosities because we are trying to resolve what we could not see. Here the issue is, how those conventional porosities were calculated. As I mentioned earlier, when we look at core data, we have to QC them. What happened here was that the porosities which had core porosities which were more than 36% were used for calibration for the previous calculations and those give very high log porosities which were even more than 36% in some cases. So that is why you have a higher porosities on the conventional than the Thomas-Steiber. If you would have used a similar approach for conventional, we would have got lower porosity in the thin beds from the conventional.