- Now that we're more into engineering considerations, this is a neat situation we were involved in, map view on top and side view on bottom. This is two wells built off the same pad. They were purposely drilled into different benches. The one on the right is in the upper bench, the B bench. The one on the left is down in the C bench. We went ahead and drilled these wells, and then, it's what we call zipper frac, which is merely an economic reference in that we are frac'ing the two wells simultaneously. In other words, everything up on surface for the frac'ing technique. We frac stage one on the well on the right. We frac stage one on the well on the left and then we come back and do stage two, back and forth. So, the chemistry of what we're putting down hole in the sand, in the prop, and all that, it's all identical. So, we ended up with very radically different frac results. The well on the right has a much bigger stimulated rock volume. The well on the left appears to be much smaller. This goes even further. Here's the zoom in on that single stage in bench C or the lower bench well in here. And, if you look at the lower graph, it kinda tells you when the microseismic event took place. You'll notice that, let me get a, what you'll notice is early on we did not have, we did not have very many microseismic events as we were putting the pad away, and in this case, putting a hundred mesh sand away. At the very end of the job when we were putting away the coarser sand, the 40, 70 mesh, we actually had most of our microseismic events. Then we go to the second well where we're up in the B bench and you see a completely different relationship there. You see that most all of the microseismic events happen during the initial putting away of the pad. Didn't get much during hundred mesh. Settled a few more microseismic events at the tail end of the hundred mesh and as we were putting the 40, 70 sand away. Now, this profile took place well after well. I'm gonna go back here real quick. There we go. We have a stimulated rock volume that's greater on the right side consistently, stage after stage, as we were doing the same kind of frac in the B bench. The B bench reacted in this style whereas the C bench on the left had a much smaller stimulated rock volume. Now, here's the unexpected result. The well on the left is the better producing well. This is something else that we'll be getting into a little later, but the concept of stimulated rock volumes, we're trying to concentrate more near well bore seems to be improving the performance of a lot of our wells. The point to take away from these three slides is that the same rock receiving the same, or I should say slightly different benches receiving the exact same treatment react completely differently. Something to know about. Here's another issue that we learned about through the play. And that is, our pancake stack of benches out here all have their own unique frac gradients. What's very interesting is that the B bench has the lowest frac gradient of the Wolfcamp benches. The highest frac gradient happens to be the A bench and it's overlain by the dean of the lowermost sprayberry section, which has the lowest frac gradient of the entire column out here. And then, of course, at the bottom of the section is the C bench and it has an intermediate average frac gradient. Well, it just so happens out here on straight petro-physical analysis, the A bench usually looks like it's the slightly juicier bench of the three in the Wolfcamp. A lot of the early wells were put in the A bench, but because it had the frac gradient, you'd have to get after it with the most energy, the most vigor. Generally, nobody knew that they were gonna blow the top off of the dean. That's essentially what happened to a lot of the early fracs. So, the B bench is the bench that initially had the greatest success because one, it was easiest to frac. And two, it didn't break through the A and frac into the dean. I call this the Mylar Chip Bag Syndrome. If you think in terms of opening up a chip bag, you try to pull the two sides of the bag open to open the chips, it has a resistance and by the time you finish popping the top of that bag up, there's a very good chance you rip all the way down the side. Well, it's the same issue that we had here with our stacked pancake of benches in here. The A has to be frac'd very, very differently than the B or the C. That was just another interesting scale issue. Some more issues in here on engineering and that's kind of the evolution of our frac systems. It began out here in, we'll call it a standard 7500 foot lateral that we would have only maybe six, eight stages. They'd be very widely spaced and they wouldnt have many clusters in them. We generally were doing cross-link gels, and we really were trying to wing frac. That is evolved through time down to a great many more stages, very, very short spacing. As a matter of fact, the technique's even picked up a name. It's SSL technology, or shortened stage link and we are generally using all slick water, some variance on that, some lineal gel at the very end sometimes. But, essentially, it's gone from cross-link gels to slick water fracs. You're looking for complex frac initiation in here as opposed to wing frac, and you're looking generally at quite a few more clusters, so that you're spreading that energy more evenly out along the well bore. And this, you can kinda see kind of the evolution here. I've put a little chart together. Overall, our general lateral links have grown considerably. Our number of stages have grown considerably. Usually don't see any wells by any of our partners or other operators that are less than somewhere in the 30's. Clusters where we're seeing a lot of four and five and sometimes six, seven, eight clusters even in a shortened stage length. I've already mentioned some of the fluid type changes. The volumes have gone up pretty dramatically. The sand types have gone a little bit finer, simply because we're using slick water, so they're a little easier to keep entrained in the frac fluid. We're going with a few more exotic issues, but primarily you're seeing mostly beginning your frac stages with hundred mesh, then finishing up with 40, 70, with some variations. One of the big things that's going on right now is I think we've more than doubled our sand concentrations per foot out here. That translates into from stages, we used to be pretty darn light, hundred to three hundred thousand pounds per stage. Well, really now a lightweight well is 250 and sometimes, the wells are getting more like six, seven hundred thousand pounds per stage. Maybe even getting a little old in that a lot of our most recent wells by numerous operators are at or in excess of two thousand pounds per foot which is getting in that six, seven hundred plus pounds per stage. The rates that we put things away have gone up quite a bit. As I have mentioned, we want complex fractures that we really wanna play off the natural fracture systems. It's important to have the natural fractures and then to complex frag, using that as a stepping stone, the natural fracture system. One issue in here that's changed a lot is that we've been designing our fracs for fracs for frac containment near well bore. In other words, over here in the next slide is to dramatically reduce the stimulated rock volume. Now, from conventional reservoir simulation, this is quite a departure. Normally, we're looking at wanting as large an SRV as possible. Looks like in shield plays, it's impractical to think you're gonna move oil through rock as tight as we're dealing with for very long distances. So, rather than thinking that you're actually going to drain six or seven hundred feet away from the well bore, the intention now is more like 150 to a max or maybe 250 feet diameter around the well bore. It just simply translates into better performing wells. That's what we're kind of summarizing here on the left well is better IP, better IP 30, looks like better EUR's. But, this process has a lot of potential implications if your SRV is going down because you're trying to control your frac height and your frac length, and increase that near bore, well bore complexity then your recovery factors have to be going up, and that's what we think is happening out here. If we have this issue of reducing our stimulated rock volume with all the implications, it also means that the typical bench in here is 350 to 400 feet thick. Well, if we're really reducing those SRV's down and if we start placing these well bores kind of in a chevron pattern between our different benches, this may leave a full bench in between existing benches that we should be stimulating. We could be leaving way too much rock behind unstimulated. Our vertical separations are anywhere from 120 to 400 feet, so if our SRV's are only looking out 150 feet, then we really should be looking at an intermediate bench in most of these cases, trying to decide what kind of density patterns to be drilling out here. People are trying all sorts of density patterns from four to 16 wells across a mile section. We're getting really good recoveries on both ends of the spectrum and everything in between, so it's an evolving analysis right now. But generally, we tend to be going towards, probably smaller SRV's , more laterals in sections, and what's really interesting is these are the sames sorts of trends we're seeing over in the Bakken and Eagle Ford. We're just a few years behind those others. But bottom line implication is that when I originally talked about that we had 11 to 13 ultimate benches out here, that was without reducing the stimulated rock volumes. So, it's a really cool implication for how much more additional drilling we may be involved with out here. That kind of wraps up things for what I was talking about in the more technical areas, and as I had promised, we've been all over the map. What I'd like to do is take a drink of water, kind of prep us for the second part.