- [Instructor] So what is the microfracturing technique? I'm showing here a part of a formation testing tool. You have, see, on the left side there's a figure that shows these dual-packers, these upper and lower elements that are spaced out by one meter spacing. The tool has a downhole pressure gauge, and it also has a downhole hydraulic pump. In most cases, we can weigh this in a open-hole environment on a wireline cable and use the formation testing tools without entry to pump fluid from the formation so that we can get an estimate of the reservoir pressure and we can also collect low contamination fluid samples. This service is available from all the major line company. Schlumberger calls it MDT, Halliburton calls it RDT, Baker calls it RCI. And we can also use the tool in reverse to pump fluid in the formation and to induce a hydraulic fracture, which is why it's called the microfracturing technique. In this case, we are targeting a shale formation. We often bring the tool in an open hole environment on a wireline cable. We can pass the line to the tool to turn on our hydraulic pump. And we can use that pump to pump drilling mud in the inflatable packers. So now we have isolated the source. And once we do that, we keep pumping fluid and we keep pumping until we break the dam rocks. Usually it takes a couple of gallons of fluid, maybe less than three liters to induce a hydraulic fracture. We can repeat the test multiple times at the same location. And when we have confidence in the research, we can deflate the packers and test another source. So in a really short span of time, you can get a pretty accurate vertical stress profile in the entire pilot hole. So in essence, what we have is a Downhole Rock Mechanics Lab. That's what I like to call it. And here's the microfracturing technique. I'm showing a pressure versus time plot, and the principle is also applicable for other forms of injection follow-up tests such as leak after, FITs, or defect. So what we have in the plot is pressure on the y-axis and time and flow rate on the x-axis. Let's start with the left side of this plot. So prior to inducing a hydraulic fracture, what we have is a closed system. And in a closed system, as you pump fluids at a constant rate, what happens is that the pressure is gonna ramp up. You see that pressure's increasing. And at a certain point of time, we reach the breakdown pressure in which we mean that we are inducing a new hydraulic fracture here. Boom. After that, if you continue injecting fluid, you are propagating that fracture farther in the formation. At a certain point of time we stop our injection process and we can start recording the follow-up response. So we get closer pressure over here, and then we bleed off the pressure through hydrostatic. Now we can restart the process that we did earlier. So now we are reopening a fracture that we had initially created, propagated farther in the formation, and then start the injection process again. So the closure pressure from the first and second cycle looks fairly repeatable. That tells us that, yes, we have determined the minimum in-situ stress and we can decide to end the test. If not, we can add a third or fourth or fifth cycle of injection follow-up also. When it comes to similar injection follow-up tests, you have the FIT, or the Formation Integrity Test. And in the FIT, you aren't even breaking down the formation. You are just increasing the pressure up to a certain weight, maybe 15 PPG, 16 PPG, and see if the formation takes it. When it comes to a leak-off test or a defect test, you just have one and follow up in both cases. So in the microfracturing tests, doing this downhole experiment two, three, four times at the same location, and at multiple locations in the reservoir, watching it in real time, analyzing it with full control on the flow rate, on the pressure stresses. This technique is way more advanced than anything else that's out there. Now some of you might be wondering how are we are able to identify when that fracture is closing. And the way it works is that the, the only thing that's gonna be different, depending on whether that fracture is open or closed. And by looking at the inflection point in the client analyses flows, we are able to identify when that fracture is closing. And there are various techniques available for that. There's the square-root time plot, G-function plot, log-log pressure versus time plot. I'm not gonna get in the details of this because we can spend an entire day talking about the pluses and minuses of each of these approaches, when to use which one. Suffice to say that the G-function plot is the most popular and commonly used approach. Something else to talk about is the stresses near the wellbore. Once we drill a new well, we have this hoop stress or the stress gauge in the new wellbore region. And when we acquire mircofrac measurement, we ought to make sure that the measurements are not multiple types of injection follow-up. And we also want to make sure that the boreholes that we pump are sufficient so that the microfractures are propagated at least four wellbore radii away.