- One area where scale seems to repeat itself would be in facies, in laminations, and textural relationships. In this slide, what we have in the upper left corner is an outcrop picture, actually of some Woodford, however, from all our experience downhole in the Wolfcamp with our image logs and everything, this in an extremely good representation of the texture of the rocks that we deal with. On the several foot, five to ten foot scale, you can see blocked ear and more finely laminated textures. Finely laminated stuff at this level is a quarter to a tenth of an inch thick that you can check on visually. You move down to the lower left, into a core box where we've taken a core out of the Wolfcamp, we've sliced the rock open, and now we're starting to see a repeat of coarser and finer textures, with the finer laminae down in the tenths to hundredths of an inch thick. It's a little hard to see on this slide, but that's just one of the recurring elements that I saw with scale. And then, when you go into fence section work you see this repetition of thin lamination scales on a much smaller scale. Once again, you'll notice in the lower right of the thin section there's a scale of half a millimeter. The vertical height of that image is roughly three millimeters and we have three different deposits in there. In the middle we actually have a recognizable skeletal lag debri deposit. It's overlain by fairly heavily bioturbated pelagic deposits. Both of these lie on top of relatively undisturbed pelagic deposits. But we can take this even one step further. On the next slide, once we go in and start working with our SEM micrographs what we see in the center, upper picture is a zoom in at about 35 microns of inter-granular and solution porosity in the matrix, and then we have scattered bits of kerogen throughout. Look at the next two slides below that, and there in the twelve to eighteen micron size, lower left we can actually see the kerogen with the vacuoles from kerogen conversion into hydro-carbon. Both on the outer edges and within the kerogen. And then, we've got a really neat picture on the lower right, where we're actually looking inside one of those kerogen pieces at the nano-pores systems. The point of all these systems of scale as we're going down finer and finer, and smaller and smaller is that we have these relationships of what we call, out in the Wolfcamp, a hyber-deprositional environment where we have inter-granular and solution perosity in the matrix, and then these relationships repeat themselves as you go smaller and smaller. Next concept area. When you first enter and start working an area, looking at shale potentials in here is that your primary tool to get started, in my opinion, is looking at your mud logs. But the problem is that that's where you'll see your gas and sample shows to see if you have any interest at all in the shales in the area of interest. When we came out to a lot of our Wolfcamp we are dealing with historical mud logging. Those results are extremely variable, basically because you've got a variety of different people using a variety of different equipment, say, some mud loggers use took equipment, some use analytical equipment, but they're not calibrated to one another. There isn't any normalization process. You get a lot of inherent variability in the Wolfcamp shale shows themselves, so trying to come up with some sort of comparative relationship between wells pretty much is impossible, but that old data is what you've got to work with, so how do you manage? The way we've always managed is, first, your expectation is that when you come out to your area of interest, you're going to have a high level of variability. You're going to have no shows, and moderate shows, and great shows with and without any record of sample shows. And it's going to vary. You could have all these situations all in the very same section of land. One square mile, you can have everything. All kind of variability. What you have to do is you have to have patience, and you have to look for the existence of shows in your area without expecting it to be consistent. The big, real trouble flag that we would always call is that if you're not seeing any shows in any of your mud logs, something's really wrong. Something's wrong with shale for prospectivity. Now the next question is, mud logging data and mud logging techniques have improved greatly, and they have. But does that solve the problems? Not really. Problems continue because even if everything were perfectly normalizable between modern mud logs, which they still are, but the samples themselves vary greatly. Here is a great example of that. We've got two sections of land here where we've done some drilling. These wells in here. These are all using the same mud logging company, a very similar time period. Let's take a look at this well over here on the right side of the screen. That well, what you're seeing in all four of these mud log sections is, this is the same section down in the Wolfcamp, that's several hundred feet thick. I've put the hot-wired gas scale on each of these logs. On this well over here on the right you can see it's zero to 1750, which implies that we're getting relatively decent gas shows throughout the section. You move over westward in the section to this well over here. In that same section you can see the hot-wired gas is scaled zero to 400. And as you can see, essentially you're getting very, very poor shows throughout the Wolfcamp section there. Then, we move over to the next section westward. Over to these two wells that are on the same drilling pad. What you see here is, over on the north side of the pad you have mud log shows that are fairly consistent through the section. Zero to 500 scaling, but on that same pad the second well goes through the Wolfcamp section, and its scale is zero to 175 with not very many shales at all, even on the same drilling pad. What you end up with is this kind of variability just because of the Wolfcamp variability inherent in the samples you're looking at. It doesn't stop there. This is another great example. Now, this is a little bit small on scale, so what I'd like you to look at in here is that this is all in the same well bore. The situation here was we were drilling on down into our curve, getting ready to land our lateral. Our curve angle was not building quickly enough, so what we ended up doing was pulling back up, setting a plug, and re-drill the curve a little more aggressively. What's really cool about this example is that everything is being held constant here. The mud log personnel, the well equipment, the mud system. Everything in here is just about identically the same from drilling the first curve to drilling the second curve. What I have here again is, I'm highlighting the scales. The original curve that we had to re-drill off of this well the scale is zero to 120. If you look through that entire log there, the hotwire gas and even some of the sample shows that you can see in yellow and orange in there. We've got a lot of shows throughout the section, but its scaling is zero to 120. Then we came back and re-drilled the curve, and re-drilled that curve and the same mudloggers with the same equipment are seeing continuous gas shows, but they're almost in order of magnitude greater, zero to 900 in here, and the exact zones where you're seeing your sample shows have moved around a little bit as well. This is the kind of variability just feet away from one another that you can expect. Let me clear this off. Go to the next topic here. Broad geo-scientific topic is the problem when we're trying to do petrophysical analysis. When you're first entering an area you're having to live with the logs that exist in an area. This slide and the next slide are from logs in the same immediate area, they're just showing resistivity curves as you're going through some of the upper and lower Wolfcamp shales. The first three logs on this slide, you can see these are all brine, wells logged in brine, with highly variable mud resistivities. On the left: one point one, middle: point one seven, to the right: point zero four. However, as you can see, the resistivity profiles in the identical sections are varying pretty dramatically from one another. And if you were trying to normalize, these three would not normalize, because they don't go in the same direction based on the brine resistivities. But the problem gets even progressively worse. You come over here to the next slide, and now we're dealing with non-brine. The first well, a lot of wells in our area, are air drilled. Many of the wells will be logged in an air-filled hole. Center log is oil based mud, the right one is fresh water mud at a resistivity of three point two eight. Once again, you can see inconsistent relationships between logs. I have done a lot of work, and talked with a lot of consulting companies about how you normalize this stuff, and nobody really comes up with a good answer. And now, if you have straight out, very modern logs in the area where you have good sets of, say five different resistivity curves and compensation, you can do a lot better job. But we're talking about going into areas where you don't have anything started up yet. You have to live with what you have. Just in general, resistivity scales are hard to use, and hard to normalize. But, you live with what you have at hand. Quantitative analysis, in my opinion, is pretty dangerous. What I always like to do is I use qualitative analysis, and I try to group the logs according to what kind of fluids were used in the hole. This allows you to do some resistivity mapping, but it really requires interpretive care. Using cutoffs seen, I look at stuff that's over 20 ohms. It is very, very hazardous. You really have to be interpretive about what's going into those assumptions. These scaling issues occur with the other logs out there, you know, resistivity logs, in the grand scheme of things are easier to normalize than many things. What really gets scary is going through the decades trying to normalize neutron logs, and a bunch of the other logs all have their difficulties, as well. What I'm really, the point I'm trying to make here is, petrophysics... It becomes a major issue to try to manage. We've got a lot of old core and old log data out there, but you would literally need a huge army of petrophysicists to get things truly quantitative. To do that the time and resources become unreasonable, so you just have to realize that there's going to be a business and economic practical limit on what you can do. Moving onto another geoscientific concept. That is, just looking at what we have in the Midland basin compared to other basin. We have two other major shale oil plays in the country. One's the Eagle Ford, the other one's Bakken. They are primarily one zone established to date. Each of them has, perhaps, a second major zone. Maybe each of them has two or three minor associated zones that may be productive in localized areas. Really, what you're looking at in most shale oil plays is one, two solid zones. Maybe a couple others on a limited basis. What I didn't know five years ago is how lucky we were in the Permian in that we have such a pancake layer of potential zones. And we have done a lot of science work in all of these zones. From the Clearfork shales through the Spraberry shales, to the primary focus right now, which is the Wolfcamp shales. And then underneath is what I like to call the Penn Shale, some people now call Cline. All of these we've taken our samples and taken cores on. Reviewed them. They all have the necessary geochemical, mineralogic, petrophysical characteristics needed for production. What we're looking at in here is that we're already into extensive development on benches A, B and C in the Wolfcamp. In a lot of areas, not all areas, but a lot of areas there's the bench D as well. We have between two and four Spraberry shale benches. At least a couple of them are already being developed in more than just limited areas throughout the Midland basin at this point, and in some cases look better performers than even the Wolfcamp shales. But we have very limited early exploitation in the Clearfork shale, though it's so early we don't know exactly what we have to work with. But, we do have a lot of basic science data that indicates that those shale benches, as long as they're deep enough, and we have enough reservoir pressure, could be productive. The same story down in the Cline. Most areas you've got one solid Cline bench, but as you get down into the middle of the southern midland basin, the Cline gets pretty thick. We have as many as two benches. What happens in here is that we have three benches already in extensive development, three benches in early delineation. Ultimately, the way it stands just today we have 11 to 13 benches to work with. That's very, very different from what we've been seeing in the other plays.