- [Voiceover] Let's talk about organic rich rocks. And so let's, a little bit of background, I'm not going to spend too much time on this but TOC is solid organic material divided into kerogen and bitumen. You have to be careful, TOC is measured in weight percent by the geo chemists and you have to convert it to volume percent for petrophysical analysis, and that's not really a trivial task. It's not obvious what that conversion should be. Bitumen is petroleum natural gas asphalts, asphaltines. Kerogen is fossilized insoluble organic material. Ro is an important concept for geochemists. It's the bitronite reflectants of coaling material and is a real important indicator of maturity and we're listing there early oil, peak oil, wet gas/condensate, and so on. Dry gas is given and in exploration activities obviously the first thing that you need to do is what realm are you in? Are you in the wet gas, dry gas, what is it? So Ro values are important. The correlation on the right is a correlation of what we'll get to of the Passey technique who uses LOM, Level of organic metamorphism and that's a correlation of LOM to Ro, because Ro is more commonly used by geologists. S1 is the free hydrocarbons made volatile at 300. S2 is bythermal cracking. S3 is CO2 by even more cracking. Tmax is the temperature of maximum rate of hydrocarbon generation. Again, immature oil generation, gas generation is given. Each one is a hydrogen index. S2 divided by TOC. O1 is the oxygen index, S3 divided by TOC which leads us to the next diagram which is the Van Krevelen diagram and I've just included it for completeness. I'm not going to really talk about it too much but it's the way that those two parameters relate to type of kerogen, oil prone rocks, gas prone rocks, or non-generative rocks. Here's another presentation of the same kind of data by Jarvie. So now let's talk about the shale model. This is a suggestion of what parameters are in now. There's lots of these around. On the left-hand side of the diagram is the solids. The non-shale matrix, that will be quartz, calcite, dolomite, whatever it might be. Salt within the shales, which probably are made up mostly of the same kind of components as the non -shale matrix and then clay solids, again this is meant to be by any means to scale, but those are the solids. The rest of the diagram is the por space and we've got four different kinds of porosity we believe. First of all, clay bound water. Secondly, TOC, total organic carbonate, again not to scale. And then finally, the yellow and the red in the far right, the red is effective porosity, remnant let's say in a shalene formation that's got maybe 70 or 80% shale, there's a little bit of clean formation in there and associated effective porosity and then the yellow is what we are calling free shale porosity. It's usually pretty small volumes and we believe it's either organic material and or fracture porosity and we'll see how we get at that in just a moment. K, so how to we do it? We should say that this is in its infancy. We are using standard triple combo data, density, neutron, PE if we've got it, acoustic if we've got it. It's not using NMR or image logs at this stage because most of our work is, and most of the work probably that a lot of you do is standard triple combo. Related interpretations including XRD and geochemical measurements, we are now in the processes of incorporating. First, as far as I can see the petrophysical quantification of geochemical data was by Quinn Passey et al in 1990, and they used log measurements to quantify TOC from standard well logs. It's the delta R log, as it's called, technique. We used that as a starting point. We found it's very robust to analyze the shale fraction to initially identify the weight and then the volumes of TOC. We used that the way that it works, and we'll see it on the next slide, is that we identified levels where TOC is low, low resistivity and then automatically recognize the equivalent porosity log readings. We choose an appropriate LOM, which is equivalent essentially to Ro and then see what the program calculates and modify choices of LOM if the match with core data is poor. So here's the next diagram. Here it is. The upper left on the left-hand side is resistivity and the arrow is pointing to a low resistivity, high reshale and then the equivalent point of that low resistivity on the porosity logs is shown, and then the program is run and you can see the correlation, pretty good correlation with measured TOC values. We then convert TOC into adsorbed hydrocarbon volume. This first equation of adsorbed gas in place has been published by several people, Matt, Halliburton, who published it, and it's an empirical correlation between TOC and the amount of gas in place per ton, actually the 16. And that probably varies from one provenance to the next but there's very little published on it but anyway, that's the starting point. The adsorbed oil in place we are, this is our equation, published, I think other people are using it. We're suggesting that the S2 value, the thermal cracking of hydrocarbons in oil, the point OO one is because S2 is measured in milligrams per gram, is giving you some kind of indication of adsorbed oil in place, but that second one, be careful, is not yet published, needs to be verified. K, so now in terms of the interpretations, what did we do? We compared TOC, the density log with RhoB to determine the correlation and adjust RhoB for TOC content. A typical relation of this adjustment, it isn't unique, is given and the reason to do this is that for standard analysis, you need to sort of eliminate TOC from the equation first, so this is what we do. We then run a basic petrophysical analysis to determine total porosity,TOC, re-shale, effective porosity, and Sw. We also at this stage determine the pyrite volume. This again is unpublished. We're hoping to get it into publications soon. Pyrite has very high grain density of five. So any pyrite will increase the density, but it also will be accompanied by increasing conductivity because pyrite is extraordinarily conductive and so we're still experimenting with the concept that we can also identify pyrite. It's very very important because pyrite, if it's around, will have grabbed onto the sulfur, and in oil as it was like the Niobrara probably will make it sweet, but if there's no pyrite, there will be sulfur. Pyrite is iron sulfite so that means if there weren't any iron minerals around for the sulfur to grab onto, there will be no pyrite and the crude should be sour. We then adjust the density neutron and Pe curves to recognize shale only responses and then calculate values just for the shale only and the clean for that matter. So the next diagram is a kind of work horse that we use. This is now a density neutron cross plot, taking out, actually pyrite and TOC, and this is the kind of pattern you get. The little green background is the area where shale clay minerals would exist on these kinds of plots. We then at this stage imperatively recognize two clay points, clay one and clay two, and the silt points with no N fee response at the bottom. From that we can then point by point calculate the volumes of clay one, clay two, and silt and we can also calculate the porosity of clay one and clay two, and then the next is a comparison of clay porosity, with shale porosity and frequently we get a miss match and that miss match, remember this is now only the shales. We've taken out effective porosity. We've taken out TOC. So this is the mismatch that we are suggesting is small amounts of porosity either fracture porosity or micro porosity associated with organic material. K, so then, what we can do, is to calculate free shale porosity and add to effective porosity to say what we term free available porosity. This is porosity in the shale where free shale hydrocarbons reside. Remember that the TOC has got adsorbed hydrocarbons but now this will define potentially, and we think more than potentially, I think it works, it will define how much free hydrocarbons, either gas or oil are available to you. K, the next diagram is now showing on the left of the raw data, same as we saw before, and then in the middle the clean formation analysis, same as we saw before, and now what we've done, the extreme right green, the big green bar there, is net pay based on the one to the left of that. That one is now the net pay of the clean formation, which we've defined as V shale less than 25%, porosity greater than 5, and so on. Then, carrying over, the rest of the panel is the shale analysis and now highlighted the pay coming out of the free available porosity in the shale. The two are totally complimentary to one another. They do not overlap. So that means, using this technique, we can quantify free hydrocarbons in the clean formation. We can also define the free hydrocarbons in the shale. Small amounts, but it does give you then the capability of looking at differentiating where this free hydrocarbons exist. Here is an example from the Antrim Shale, of Michigan, the gas prospect, project, and here we see a completely different, most of the hydrocarbons is in the shale. There's only a little bit in clean formation. We didn't show it, but there's pretty good correlation on the extreme right with TOC coming out of the core data. The Passey technique, I have a high regard for, sometimes busts and we think the busts may be a consequence of pyrite. So therefore, what we've said is that we can define hydrocarbons, free hydrocarbons, and adsorbed hyrdrocarbons. The free hydrocarbons are the ones that are going to flow to the wellbore first and behave in a relatively standard engineering fashion. Adsorbed hydrocarbons will come out later in the wells life, if at all. They will be sort of down the road. And what we've done is to show cumulative values, modified Lorenz plots have cumulative free oil on the x-axis and cumulative adsorbed oil, in this case on the y-axis from the Niobrara and then as you go up the well, the well it goes vertical, is only adsorbed oil and where it goes much gentler slope it's mostly free oil. We're using these kinds of plots to help in where should you complete in a horizontal well? In the Niobrara it will be good for example, to complete in the A or the B bench, but may be accessed by organic rich shale to get a little bit more reserves later on. Here is adsorbed versus free gas from the Antrim.