- [Presenter] So now we'll talk about a few examples. The first one here is from Avalon Shale, in Delaware Basin, and this basin spans all the way from Southeast New Mexico to West Texas, almost 2,000,000 acres, here. Operators have been producing from this basin for the past 60-some years. They were initially targeting the deeper, silurian-gas-filled caps, which are now depleted. These shallower and younger Permian-age rocks often show signs of hydrocarbons, but fears against to cap to them, led to chemical waste issues. Over the past few years, with advanced percent hydraulic pump drilling, hydraulic fracturing, multi-extract completions, there's been renewed interest in the basin and now operators are going after these upper, middle, lower Avalon Shales, first, second, third Bone Spring Sands, Wolfcamp Shale, and depending on which part of the basin you are in, all of these soils are used hydrocarbons. So, it's a very lucrative problem to solve. Soils are the cemented carbonate soils that are likely to attract buyers. So a few years back, we are getting in this basin, and we came up with an extensive completion evaluation program to answer certain key questions regarding the Carver Peninsula, Delaware Basin, and Avalon, in particular. How variable are the stresses across prospective intervals? What's the energy required to initiate a new frac? What's the contrast between frac versus pore pressure? Are frac barrier/seals effective or not? Where should we set the casing shoe? And how can we calibrate sonic log-derived stresses? So, as part of our data acquisition, we carried out micro-fracturing in one of our first exploratory wells and here is one of the results that we got. Again, I'm showing a pressure on the y-axis will sustain on the x-axis plot. And what you see is that we spent almost 30 minutes just inflating our dual-packer system. Once we had done that and isolated the well bowl, we inject first arid concentrate and right away, what you see is that the pressure is amping up. So within a few minutes, we are able to induce a new fracture. We stop our injection process and then we start recording the ISIP and closure pressure. After that, we bring down to hydrostatic and now we are repeating the test. So, in this case, we saw that the closure pressure from the first cycle and the second cycle is within 11 psi of each other and that's sufficient to make any frac design and decisions. And when we looked at the results, we noticed that we are seeing a simple relation of increasing stresses with depth. We saw relationship based on lithology. The POC, or purgeable organic carbon, areresource that we target for micro-fracturing; they actually have low closure stresses and are easier to break down. And when we tried micro-fracturing some of the cemented carbonate source, we weren't able to break them down at all and that told us that those cemented carbonate sources are effective frac barriers and also good locations for selling casing shoe. We also compared micro-frac results with DFIT and Sonic Logs and I'm showing the results on the track number 6, which is the fracture gradient track. What you see inside the micro-frac, first and second cycle is right on top of each other. The DFIT is likely higher by 403 psi/ft. And what was happening is, in this case, is that the micro-frac was acquired in the work ofhole, whereas the DFIT was in the first stage of the littoral. So even though we have the same two verticals there, actually the DFIT is about 4,000 feet away and we did notice changes in lithology from the that might have indicated changes in the stresses as well. By contrast, the Sonic Log that was acquired in thepilot hole is shown by the red line and what we see is that the sonic stresses are higher than both the micro-frac and the DFIT reserves. So from this, we realize that the sonic, more or less, over-estimating the stresses and we are able to calibrate that down. We also compare closure stresses with first year production and it's based on a seismic mapping approach where we can come up with a closure stress attribute at each work location and what we are seeing is a fairly strong relationship across seven wells. The wells at our chosen locations with low closure stresses aren't high POC, high porosity, high corrosion. They actually have higher first year production as well. And the idea behind this is that if you can come up with a truly seismic queue of closure stress, you can use it to optimize our planning depth, improve our well spot, and the frac design. Precise data requires calibration and that's where micro-fracturing comes in. If you can carry out micro-fracturing across T-exploration spread out across the basin, you can use it to calibrate our seismic data and in turn, improve any performance predictions. The next example here is from offshore deepwater. Now this, we are getting into the deeper, less forgiving targets which are difficult to map with seismic. Almost 30,000 feet deep and equally high of pressure. So it fits in that very narrow window between formation versus frac pressure, so we have to use multiple casing strings and once we, we use something called a Frac Pack completion that means we perforate and then we fracture through those perforations. And with that technique, there is a risk of seal breach. So a few years back, we were drilling this over-expensive well, and as we got close to our target section, our geomechanical model started predicting that this, something called a stress reversal, in the field. A stress reversal can occur because of the to the lithology, full pressure and structure, and it basically means that the rock stresses in the shale are much lower than the rock stresses in the pay sand underneath. So stress reversal is true and will set your frac pack completion right near the boundary between the shale and pay sand. What's going to happen is that those fractures are going to propagate up in the shale, and not only can they go in the shale, they can go beyond the shale, so it can cause a blowout. Well, we don't want that to happen, so the other option is to set out frac pack completion way below, but if you do that, you're gonna lose 120 feet of pay, since all that rock volume is something that we simulated. And that's a big hit on our reserves, based on a geo-mechanical model and that's not an option either. So we decide to add on a micro-fracturing run, at the last minute, on this over-expensive well, and anytime at Chevron, you make a last-minute change on a high-profile project, it takes a lot of change for our actual processes, lots of paperwork, lots of new things. At the time, you are carrying this stressed-out, it was the deepest micro-fracture, at the highest pressure ever performed. And we weren't even sure whether the tools were gonna work, or if the packers are gonna deflate, and as part of principle negotiations, our plan was that, in case the tool gets stuck, we'll just cement the tool in the hole. Because it is cheaper to cement it than to fish it out, at over a million dollars of base rate per day. And we ultimately decided to carry out the micro-frac test and it was a successful test. We were able to convert the tool on a y-line cable and receive it back on surface as well. We got measurements of rock stresses in the shale that told us that stress reversal is essentially true, we are not going to lose 120 feet of pay, and our geo-mechanical model requires further calibration. Here is another case study that was published by OTC, by BP and OTC recently with a Gulf of Mexico example. They carried out four micro-frac cycles. You can see them all here labeled as 1, 2, 3, 4. And they were able to break down the formation at over 25,000 psi. That's remarkable. So they had four cycles of injection fall-off within a three-hour period The next example here is a waterflood in Brownfield. This is a heavy oil reservoir in the North Sea that has been producing for the past 20-some years and now raises a means of increasing oil recovery, we are re-injecting for use in our main reservoir. So in our main zone, our injectors are injecting through it under fracturing conditions, but at the same time, those injections are constrained because we don't want to frac the seal above. But the rock stresses in the sea, they have never been measured directly, so get measures of those rock stresses in the sea, and if it turns out to be higher than what we are currently assuming in our model, we can actually increase the injection pressure and make sure that our chemical EOR project also becomes viable. So as part of our data acquisition, we drilled a new well and we acquired both sonic logs and micro-frac in the new well, and here's the comparison. What you see is that the sonic model is showing the stresses as being around 400 to 500 psi less than what we got from the micro-frac test and one of the explanations behind this was that the formation wasmuch deeper or over geological time, it has been uplifted, and that's why the sonic model is underestimating the stresses. From the micro-frac test, we got a instrument and used it to generate a new stress map for the entire field to increase the injection pressure at rate. And here's the business impact. We carried out micro-fracturing, right where I'm showing this arrow and within a few weeks of that we are at enoughto increase our injection pressure by 320 psi and increase our re-injection rate by 24,000 barrels of water per day, that led to increase in oil recovery by almost 2,000 barrels of oil per day. How often does it happen that based on one we are able to increase oil recovery in the entire field by 2,000 barrels of oil per day? This made an impact not only on the field, but on the entire business plan of the year, almost $15 million.