 As was mentioned, I'm an environmental geochemist, more like an environmental chemist by training. And my work relates to geochemical processes in porous media like soils and sediments and fractured rock. And what I do in my group is depicted by those iconic images. We do novel experiments, particularly high pressure experiments. And we combine it with advanced materials characterization as well as reactive transport modeling at a variety of scales. And you will today hear about my research. But before I get into the nuts and bolts of those details, I would like to step back and talk a little bit about the big picture that motivates me. The real overarching guiding grand challenge that inspires me every day is that we must prepare for a future that is a sustainable future that provides the world's energy needs while also protecting natural resources and not jeopardizing human health in the environment. And that is what inspires me. But when I think about that, to me, that's a call to action for transforming the view of how humans interact with the subsurface. To me, this is the century of the subsurface. The subsurface environment is a vast opportunity for shifting the way we think about how we can use the subsurface, not just for extracting fossil fuels, but also for technologies for protecting the environment and minimizing climate change. And so I want to take probably 10 minutes or so to talk about my views about this with a particular focus on geologic carbon sequestration and the role of geological processes, particularly as it relates to reliability of geologic carbon sequestration. So I have about, I think, five slides on this big picture. And then there will be a transition point where I will be happy to tell you about my work in geochemical processes. OK, this is a graphic I like to use to talk about the subsurface environment. This is a graphic produced by the Department of Energy for their subter initiative. And I like this because it shows the way we currently use the subsurface and the potential ways that we can use the subsurface, as I mentioned, for better protecting the environment, such as through geothermal energy and expanding the use of the subsurface for energy storage, which is therefore an enabling technology for intermittent renewable energy sources like wind and solar, as well as for a geologic carbon sequestration, which is down here in the middle. All of these processes require that we understand how fluids behave in the subsurface, where they go. If we're going to put fluids someplace where we want them to stay, we need to know that we have reliably contained fluids. So this is an important part of subsurface science. And I think there's a lot of research opportunities going forward in this area. And my own particular interests are related to, as I said, the geochemical processes that are at play. So now I'd like to focus on geologic carbon sequestration. And I'm going to start with this image here on the left, which is from Rob Socklow's paper from 2005. And it's a depiction of what is carbon capture and sequestration, of which geologic carbon sequestration is one part. So just so we're all on the same page, carbon capture and sequestration refers to capturing carbon dioxide from large point sources, such as coal-fired power plants, and then separating that gas from other gases, compressing it and transporting it to a place where it can be injected deep underground and reliably stored for many, many years, or indefinitely. And just to make it real, I put a photo here that I have from Canada. And Alberta, Canada, they have a very nice field research station run at the University of Calgary. And so this photo captures some of the elements of what a carbon injection site would have. Most importantly, the wellhead. This site has a large tank of CO2, as you can see in the background, which supplies this. And this is a research site as opposed to a commercial project. But I just wanted you to get a sense of what it looks like at the land surface. I put a little photo here from the 2015 Paris climate meeting. I put this here just to make the point that all indicators are that the analyses that are done for climate models, climate technologies that would stabilize the climate and the techno-economic models and analysis, all of them are in agreement that CCS is a key part of solving the problem to stabilize the climate. And so this is one of the motivating factors in this research and research of others. Well, what about the role of the United States? The United States is one of the largest emitters of greenhouse gases. Here I have a graphic of how the United States generates energy. So this is a graphic of energy consumption in the United States. And what you see is that fossil fuels still dominate energy consumption in the United States. And it has for about 100 years. So even though the use of fossil fuels has declined, it's still larger than 80%. And so we have all been pleased with how wind and solar have taken off, but they still remain a small part of the total energy generation in the United States. Worldwide, this figure of how much energy production comes from fossil fuels is about 40%. So it's smaller, but still significant. My next graphic is a concept graphic. And that is, CCS seems appropriately to be thought of as an enabling technology toward what will someday be a sustainable energy future someday. But currently, what's called the fleet of cold fired power plants around the world is the youngest it's ever been. Meaning that the number of plants that have been constructed in the last 10 years is larger than it's ever been. And so it seems unreasonable to imagine that those plants are going to shut down anytime soon. So given how coal is being used and will continue to be used for a long time, CCS seems an appropriate bridge technology to help us to mitigate greenhouse gas emissions while burning fossil fuels. What is the current status around the world of CCS operations? Currently, there are 17 that are commercial scale. Primarily, they're North America, Europe, China, and Australia. And I'd like to, on the next slide, tell two stories about commercial scale operations in the United States. So I'll tell the story about the Petranova plant in Texas and the Kemper plant in Mississippi. These two, one is a success story and one is not a success story. The Petranova plant is a large coal fired, a powered plant near Houston, Texas. And the company Energy partnered with a Japanese company to add on the technology for carbon capture. So this is post combustion capture. And the Department of Energy invested hundreds of millions of dollars to ensure the success of this, identifying this as a project which would demonstrate how carbon capture technology could be added on to retrofit coal fired power plants. And this project came in under budget and ahead of schedule and began operating a year ago, January last year, with a big celebration in April of last year. So this is a success story. The graphic on the upper right goes along with this and it shows the carbon dioxide emissions at the plant before and after the carbon capture technology was put on. Now I should say that not all of the emissions are going through the carbon capture technology. There's a slipstream that's going to the carbon capture technology where that those emissions, there's a very efficient capture of CO2. It's something like 90% of the carbon dioxide in those emissions is captured. So there is a significant reduction and I wanna point out that to run a carbon capture facility costs energy. So they have a natural gas generator just to provide the power for the carbon capture technology, but still the net carbon dioxide emissions is less than what it was before. Here's one statistic. This site, this plant captures 5,000 tons of CO2 per day. There are all sorts of ways of thinking about what is 5,000 tons of CO2. But I like this equivalent. That's equivalent to 24 rail cars of coal, which is about half of a mile of a coal train. That much carbon captured every day. It's astounding. Okay, so that's a success story. This is a story that is also reached conclusion in 2017, but not successfully. So this first one was an example where an existing plant was retrofitted. The alternative way of capturing carbon dioxide is with a different technology where the carbon dioxide is taken out of the coal before it's combusted. So it's a gasification process. This one is called IGCC, Integrated Gasification Combined Cycle, where the CO2 is removed and the remaining hydrogen gas is burned just like natural gas. This project started in 2010 and it soon went way over budget by billions of dollars and DOE continued to invest in it. And finally, last year it was canceled. And I think now it remains as a natural gas combustion plant, but there's no hope to do carbon capture and there's no hope to do any gasification from the coal. So I bring up these two examples because this is an example of new technology. This is an example of application of existing technologies. But in both cases, we do need government incentives. And so I want to get to that on my next slide. But first, what happens to the CO2 that was planned for capture here and that is being captured there? In both cases, it's being used for enhanced oil recovery. CO2 is used in enhanced oil recovery. It's a very good solvent for liquid hydrocarbons. So in a site where there's residual oil that you can't get out through conventional means, you can flood it with carbon dioxide and it will mobilize the oil. And the rule of thumb that I have there is roughly speaking, half of the CO2 that you put in for enhanced oil recovery will stay underground. And the rest is going to come up with the oil where it can be recovered and reused. So some people say, well, that's not carbon sequestration. But I think of it this way. EOR, CCS, is a bridge to this bridge. CCS will have a hard time moving forward if there's not incentive to build these expensive carbon capture plants and the IGCC plants. But if there's an economic incentive, meaning that carbon dioxide that is produced is economically valuable to the oil and gas industry, then there's a reason why that will happen. So that's the bridge to the bridge. Now let me talk specifically about government incentives because there's something really good that happened this year. There are tax credits called the 45Q tax credits for carbon sequestration. And this is something that has existed for about a decade already. But it's this year that those tax credits were made significant enough to be actually attractive that economists are predicting that this is exactly what is need to move forward with CCS being economically favorable. So in the two columns here, you can see the old 45Q numbers where the two different numbers for carbon dioxide sequestration using EOR or for disposal in a saline aquifer, $10 and $20 per ton. But now it's up to $35 and $50 per ton. So it's believed that that's going to really change things and turn the tides for CCS. That is the end of my introduction. And now I want to tell you about my research. And so we're going to continue to focus on geologic carbon sequestration, but we're going to shift to talking about geochemistry now. And I'm going to start with a geophysics type figure. This is from Johnny Wright-Quist. This is a depiction of CO2 injection target formation underground, where CO2 would be injected. And the important thing about CO2 injection underground is that there are layers in sedimentary basins with different amounts of permeability. So if you put CO2 into a porous permeable formation, then overlying it somewhere would be an impermeable formation that we would call the cap rock. And that cap rock is important because it must reliably contain the buoyant CO2 that's put underneath it. And so what's depicted in this diagram is possibly there are ways that that cap rock may become fractured or faults might be activated through the pressure of injecting fluid. When I started this work, I started to think about not so much the fault activation, but I started to think about this from a chemistry standpoint because I'm a chemist. And very early on, I thought about when you put CO2 underground, the pressure is high enough that a lot of the CO2 will dissolve in water. So much so that the carbonic acid that forms in water becomes what we actually call a strong acid. If you learn about carbonic acid and freshman chemistry, it's in the category of it's under the column weak acid, but not underground. It's a strong acid. So you could have a pH perturbation that's significant. And if you introduce an acid into a formation that's not acidified, it can respond geochemically, meaning that minerals that are easily soluble acid will dissolve readily, quickly, fast. And so this is really what motivated me early on. And there was also an injection site in Michigan, in particular, where it was a demonstration project where CO2 was injected underneath a carbonate cap rock. And I said to my student, let's get some of that rock. Let's just do some experiments in the lab that simulate what would happen if you had a fracture in that rock and you pass through it, pressurized brine that's equilibrated with CO2. And so that was our first experiment. And I'm going to get to that. It's a little bit like this graphic here. Imagine that this portion here is the injection formation. In the aqueous phase, you have carbonic acid where the dominant anion is bicarbonate. And then if possible, if there's a connected flow path through the cap rock, then that acidified brine may flow through it. And then if there are carbonate minerals in that cap rock, then they can dissolve. Early on, we decided to simplify this geochemically. For those of you who do any geochemical modeling, you know that it can very quickly become onerous in terms of the number of reactions that are modeled. We decided to keep it simple, recognizing that calcium carbonate is really the only mineral we need to worry about because it's the only one that's sufficiently abundant, thermodynamically unstable in acid, and also kinetically fast reacting. It's the only one that meets those criteria and would significantly change the void space that would ultimately create permeability that wasn't there before or increased permeability. So you see this pH 3 to 5 here. That's a significant acidity that could be a chemical perturbation that wasn't there before. So on the next slide, I'm going to show you just an overview of how we do some of these experiments. We often do these at high pressures because in order to get that pH 3 in the water, we need to have enough CO2 in the water. We don't like to substitute by just using hydrochloric acid. The interesting thing, one of the interesting things is that the anion for this acid is carbonate, and the anion for what you're dissolving is also carbonate. So there are these complex nonlinear feedbacks that don't exist if you were to just look at it with hydrochloric acid or something. So we do it under high pressure with CO2, acidified brine. This particular experiment shows that we're using X-ray computed tomography during the experiment to look at the progression of the void space over time and see how that permeability might be evolving. This image here shows that we use fractured cores. We break them to fracture them. We don't cut them. And then one of the things that we do is we use the X-ray CT imaging to map the apertures onto a 2D plane. I'm going to show you a little bit more collectively how we look at the results from these experiments. And I'm going to do it focusing on this rock here. So this is the Amherstberg Limestone. This is the cap rock for the Michigan CO2 Injection Demonstration Site. And that was an interesting project. We paid attention to it carefully. That was a site that during their monitoring, they did end up having a lot of dissolution of that cap rock. And then they relabeled it. They called it enhanced storage capacity. And then the formation above it became the one they were calling the cap rock. So anyway, we're going to talk about that one. And if you can see it, this is an evaporate rock. And it's not a stratified shale like this one, Eau Claire shale. I don't know. Is there a tech person? Maybe there's something here. Maybe. OK, good. Yeah, I think it's a good idea to turn the lights down. OK, so on this next slide, I'm showing you some of the way we think we do our results. On the left-hand side are how we interpret the X-ray CT commuted tomography data. So as I said, we do 3D XCT imaging of the core. But one of the ways we look at the fracture is we just make a projection of the apertures onto a 2D plane. So here's an example of the results from that one of the experiments with the Amersberg limestone. Before, the apertures are all small and mostly uniform everywhere. And afterwards, the apertures have increased and there's a lot of heterogeneity. Another way we look at it is we look at the whole 3D structure. And so in a minute, I'm going to show you how we fly through this stack of scans to look at the 3D structure. And then the other thing we always do is after we're done looking at it as an intact specimen in 3D, then we section it in different ways and we look at it using the SEM, particularly with backscattered electron microscopy. And so, and I should say, then we quantify permeability. So we take those 2D aperture maps and we do a 2D model of the pressure flow field using the local cubic law model. And so for a given flow rate, we map the, we compute the pressure field for this 2D space. And then we have pressure gradient across the whole fracture as if you were to flow water through it and then we infer permeability and transmissivity. So I'm going to come back to this slide because I want to tell you about those SEM images in the upper right. But here's what I'm going to do. And I decided this on the plane yesterday. I was thinking like, you know, I have like 10 years worth of work I want to tell you all about. How am I going to do this? And I came up with this on the long flight from the east coast that I'm going to put all the results from about 10 years in this framework. And you're going to think it's very clever because I think it's clever. I'm calling this the permeability speedometer. When we flow acid through these rocks, usually the permeability increases because we're dissolving some amount of the rock. Usually it's the calcite what we're dissolving. So I have a speedometer here. And we'll take this benchmark here as there's no change in permeability. So everything to the right of this is a positive increase in permeability. Down here would be the permeability decreases. And up here I put another benchmark. And I'm calling it the base case. And this is a, if you could imagine a situation where we're just going to model how much would, how much mass, mineral mass would be dissolved over time if we just flow the acid through, let it get buffered as it goes along in 1D. But we don't account for any roughness or two-dimensional variation. It's just a 1D reactive transport model accounting for kinetics, but simple 1D reactive transport model. So that's my base case. And then I'm going to call things on this side is there is permeability increase, but it's less than expected. And similarly, permeability increase, but more than expected. That'll become more clear in a minute. But just to jump to the chase, this is what you're going to see at the end of the talk. You're going to see that we've found experiments that fit all over this map, including cases where the permeability decreases. This paper is titled, Dissolution Induced Permeability Decrease. So I'll get to that in a minute. So here's what I want to do. I'm going to show you animations of us flying through these cores. These are the XCT image stacks. On the left, I have this Amherstberg limestone that I've been telling you about. That's the cap rock for the Michigan demonstration site. On the right, I have the Indiana limestone. This is not a cap rock. The story about why we looked at the Indiana limestone is I had a student, Brian Ellis, who's now a professor at the University of Michigan, who did this experiment. And it ended up with such complexity that my next student said, get rid of all that complexity in the mineralogy. I'm just going to find a model rock that's spatially uniform one mineral. And then I'm going to control other factors, like the reactivity of the solution. So that student said, I'm going to look at the Indiana limestone and I thought, that's not going to be interesting, but OK. And it turns out it was interesting, but for a completely different reason is this one. So what I'm going to do when I click is you're going to fly through. This is animation. It's not an animation in time. You're flying through the stack of rocks. And what I want you to do is look. Did we get the lights changed? No. They did? OK. So I want you to look very carefully at the aperture change in the reacted rock for the Amherstberg limestone. And what you see is the aperture is larger. So yes, there has been a lot of mineral dissolved. But you don't see a nice, clean, smooth edge. This rock is a dolomitic limestone. So it's like a 50-50 mix of dolomite and calcite. The dolomite is soluble, but it's kinetically limited. And so it remains undissolved largely. And so what gets created there, and you can see it particularly there where it ended, is this matrix that we call the degraded zone that is pretty much dolomite where the calcite has been dissolved out of it. So that turned out to be a more complex scenario than what we thought it would be. And I'll get to that in a minute. And then this one is the one where it's only calcite. So there's not going to be any dolomite matrix left over. But we found something different about this experiment that you only get when you have a homogeneous rock. Is it going? So what you're seeing here is that there are parts of the fracture that remain closed completely. And then there are other parts of the fracture that where the aperture has increased substantially. And then when you get to the end, you get to a region where the amount that's reacted is really localized. Yeah. Yeah. For the purpose of the experimentation to keep the flow from going around the edges, not to study the geomechanical effects. So what you see at the very end is that the reacted zone is confined to a very small part of the fracture. And so this means that there has been a channel that has formed. And this is a phenomena that is really important in terms of permeability evolution. I think I got it in there twice. OK. So what we did with that first one, the one with the Amherstberg limestone where there was that degraded matrix, is that we did CFD modeling. So we made a finite element mesh of the fracture. And what we were able to do is compute the transmissivity before and after. And with modeling, it allowed us to think about that fracture in different ways. We ran the scenario of, what if that degraded dolomite part is actually part of the flow field? What if it's not at all part of the flow field? So we were able to explore a lot of things. But ultimately, the important thing is that there has been an increase in the transmissivity. But it turns out it's far less than what it would be if it were simply just a parallel, smooth, parallel place. So all of that roughness that got created, created tortuosity that wasn't there before. And I want to go back now to these images. So when we section it, we see a couple of things. There on the right, we see that dolomite matrix with the dissolved calcite that has come out of it. It's not clear to what extent that's playing a role in flow or not. And then this is the interesting image for me, because the direction of flow here, it would be up. And it's a sedimentary rock. So there are sometimes clay layers. And they form a stricture. And they're not going to dissolve any time fast under these conditions. And so all this calcite that's dissolving around it may not have the real controlling effect on the permeability, because that stricture will remain. And that actually shows up in the aperture map. Right in the middle, you see the blue band going across. That's actually that clay layer that's going to remain there unaffected. So if flow is going in this direction, that can control the permeability, despite the fact that there's all this dissolution of calcite around it. OK, so I've got to go ahead again here. OK, now I told you that the Indiana limestone is not a cap rock. And my student wanted to study it because it was mineralogically homogeneous. She's a scientist who likes controllable model systems. So this is the one that turned out to be interesting, because when you have a homogeneous rock, you can get channels. And you can't get this easily if it is mineralogically heterogeneous. And so this is an experiment where we did XCT imaging during the experiment. So we actually had aperture maps over time. So that's what you see here. And in the histogram of the apertures, you see initially the apertures are small. And we have a unimodal distribution. And over time, we end up with a bimodal distribution where that second mode is from all those large apertures, but only in the channel. So this is explainable, because in a rock like this, you can have a positive feedback. If there is any unevenness, then there's going to be more flow there, and so more delivery of acid there, and so more reaction there, and more removal of mass there. And so it's even bigger, so there's going to be more flow there. So the positive feedback makes the channel form larger over time and larger as you go downstream. And just to make the point about how important channels are in permeability evolution, I have two simple tracer flow simulations just to help you see the difference between before and after the channel is formed. And so the two panels in the red, I'm going to click, and you'll see the tracer go through. And you can compare before and after how fast it takes for the tracer to go through. So that's pretty much done now. And the red that remains is a little bit of tracer that has been transported laterally into the region where there isn't a lot of flow, and it'll pretty much stay there. And this one still hasn't made it to the outlet yet. OK, so I want to talk a little bit about how we're interpreting this experiment with the channel forming. So this is, let me explain this diagram here. The x-axis is the volume of the fracture relative to the initial volume. So it increases because calcite has dissolved. And on the x-axis, I have the permeability relative to the initial permeability. So both of these things are going up. And this baseline, this base case that I was talking about earlier, is right here in this red. And we had some uncertainty bounds because there's uncertainty about the kinetic coefficients for the reaction rate. But this is that 1D react transport simulation. And so the way to interpret this is that, and by the way, those time points at the end are the same time points. Far less calcite has dissolved in the experiment than one would expect from 1D react transport modeling. So less mineral has dissolved, but the permeability increase is larger than it would be. So it doesn't take much. You don't remove much mass at all, but you get a huge effect in terms of permeability evolution. At that point, I really did stop and think, but wait a minute. We're looking at a rock that's not representative of the types of shales and evaporites that are cap rocks for CO2 injection scenarios. And the shales and other cap rocks are mineralogically complex, heterogeneous, and often have bedding planes. So the next piece of work I'm going to show you is a student of mine who did simulations of rocks with different patterns of reactive minerals and different amounts of calcite. And he also wanted to look at the effect of normal stress. So in this case, we simulated there being normal stress so that over time, as the fracture dissolves, there's a possibility that it could close up. So here's how I'm going to show you this simulation. This is not one with mineral heterogeneity. This is the base case for this study, where it's spatially uniform, but with heterogeneity in the initial aperture field. And this one with no normal load and then with 50 megapascals of normal stress. And this yellow map here shows all the contact points. And I want you to watch them because over time, there we go, over time, they get dissolved away. They're dissolving away, but the stress has to be held by the fracture somewhere so new contact points are formed. And so what you're seeing, what you saw, is that the black dots moved downstream. So the difference is that downstream now becomes more compressed than if that normal load weren't there. So this has a significant effect on the permeability evolution. With these kinds of simulations, we also looked at more realistic cap rocks with mineral heterogeneity. So we looked at this Amherstberg limestone, which has a mineral heterogeneity organized in this sort of nodular way. And then we looked at this very laminated Eagleford shale. And I can tell you details about how we came up with the maps. So this is just a repeat of what I just showed you. And so these are the binary maps of calcite, no calcite. So reactive mineral is white, and black means basically non-reactive mineral. And so I'll click, and I'll show you these simulations of the evolving aperture map here. And the result is really quite different. In this case, a channel could form and actually form faster than without the big dolomite nodule in the middle. Because having some patches of non-reactive mineral allows for the acid to be delivered downstream faster. Because wherever it's reacting, it's being buffered and neutralized. But if it's just passing over non-reactive mineral, it goes faster downstream. So this is a case where a channel formed and it formed faster than in this case. In the case on the far right with this stratified rock, no channel can form. But this is a case that initially acid can be delivered downstream quickly. But no sort of runaway permeability will happen because there's no channel. And so these are the resulting plots of how the permeability looks over time. This runaway kind of behavior is when you have a channel. And this is the case when you have a stratified rock. It increases initially, and then nothing else is changing. There could still be calcite dissolving. But it's those strictures that are caused by these layers of non-reactive mineral are controlling the permeability after some time. This is a really good outcome because a lot of rocks look like this. Sedimentary rocks are often this way. I have a very cool experiment here that I'm going to skip. And this is an experiment where we did reactive flow through a fracture. And then we did friction measurements to see how that degraded zone would act in terms of the strength of the fracture. And I'm going to skip it because I don't have time. I could answer questions about it. We'll do it that way. OK, this is a partnership with Penn State where we did the reaction experiments and they did the friction measurements. OK, are you ready to see the permeability speedometer results? Yes. OK, so here they all are. Let me jump over that one because I'll point out the ones we talked about. There's the Emmersburg limestone, which because it had all that roughness, its permeability was not as large as you would expect. Way over here is the experiment with the channel forming. This channel that formed around these nodular non-reactive minerals went faster than this one. If you apply mechanical load, which does exist in the subsurface, it will ameliorate that. But still, there's a channel will form. This was an experiment I haven't talked about where there was just less acid and everything took longer, so it was more on the baseline. And down here is the one that is mimicking the Eagleford shale. And because of all that stratification, the permeability increases and then doesn't increase anymore. And this one is the one I mentioned where we were able to measure permeability decrease. Why? We were confused because this was a replicate of this experiment. Both were the Emmersburg limestone. We took cores that were probably just a few centimeters from each other. We replicated the experiment. And one gave this result and one gave this result. And when we sectioned it and we looked at what was in the fracture, what we saw is that all of these clay particles had been mobilized because they were part of the rock. The calcite was holding them, cementing them together. And then the calcite dissolved and all those clay particles migrated and clogged up the fracture. And why that didn't happen here? It's just spatial heterogeneity gave us these completely different results. I have my last slide is this one. So I will end with these points. Geological reservoirs are essential for the gigaton CO2 per year scale sequestration that we would need to do to stabilize the climate. And geological reservoirs are therefore key for negative emissions of greenhouse gases. Reservoir storage security must be verifiable, especially with the 45-Q tax credits. In order to get those tax credits, it's going to be necessary to say that the CO2 has been stored permanently. That's the word that is used permanently. And so the question that I've been investigating is, will fractures and carbonate cap rocks erode in jeopardized storage security? My answer to that question, after looking at this for 10 years, is probably not. Probably not. I think that this kind of scenario of runaway permeability is mitigated by the mineralogical complexity and heterogeneity of these rocks. Finally, large-scale simulations, which I didn't include because of lack of time, reveal multiple trapping mechanisms. If you put CO2 deep underground and then actually many rocks that serve as cap rocks, if it does leak, it'll probably dissolve into the next formation or be trapped by the next layer. And then if it leaks again, it'll dissolve more or be trapped. So there are many, many opportunities for trapping underground, which adds to our confidence of the reliability of reliably containing CO2. That is my last point. Thank you very much for your attention. Professor, are the others going to have some time for a few questions? I'm going to go ahead and get some questions. I've been meeting Greenhouse gas targets. I'm certainly glad to hear you have that. You can go ahead and get some questions. So I'll tell you a quick and experimental result from just after the Civil War when I was working for Shell. And so we were working on our projects in West Texas, which are in Dolomites. And the worry was that we would inject CO2 to dissolve them in the brine and make wormholes like that. And then when you got close to a production well, where the pressure would come down, all that stuff would come out of solution and bang. You'd plug up all the wells, which was perceived to be bad. So the first experiment was with a nice calcite core and pure, just plain old water with plenty of CO2 dissolved in it, and sure enough, wormholes like that. And then a sequence of experiments was done with actual reservoir rock and with reservoir rocks. And the combination of those two was much less of a problem. They already had scale problems in West Texas anyway. So it turns out things were not much worse. And what was never clear at the time, and I didn't do the answer to this question, is that was it the structure of the rock? Or was it all the other stuff that was in the brines that helped with all the debuffering? Or some combination of the two? Yeah, I absolutely think it's the structure of the rock. And the spatial organization of the variability in the pore space, heterogeneity, as well as the non-reactive minerals that aren't going to contribute to these wormholes. Did you use just pure water with a saturated sand cube? It's brine. It's a recipe that mimics subsurface brine, but not that complex. It's mostly sodium chloride. But chemically, I just don't think that there's, I mean, unless you're adding sulfate that'll precipitate with barium. I don't think there's anything that interesting about the brine other than the CO2 itself. And the salinity. The salinity is important. Yeah. Are these CCS facilities located in not any of the sites that sit near or on the place that the carbon will be stored? That's a good question. So if we take, if we think about gas pipeline transport in the United States, we've got two examples. We've got natural gas pipelines that go all over the United States, long distances. It's not inexpensive. But the point is it's, technologically, it's already done. So one way we could think about it is that's possible. But the other thing is that if we think about the projects that have been set up that have been deemed economically favorable, they're transporting the gas like Petronova, the transport was 80 miles to where it was going to be used. So that might give a sense of the feasibility of transporting it. And the other thing I'll say is that, and Lynn, maybe you have a perspective on this. But I know that in CO2 for EOR, CO2 is not transported that far. Meaning that there are many sites where EOR could be done, where it's not done, because the CO2 is not readily available locally. And these plants give an opportunity for CO2 to be done, where it wouldn't otherwise have been done. Yeah, I would say that the national recovery is always limited by availability of the gas at a price that somebody's willing to pay. But it can be transported long distances. There are multiple pipelines that go from the Fort Fortress area down to the West Texas. And those have been long and don't become mild on plants. In your fracture experiments, you're working with cores of a finite size. And how can you, well, the material medium parameters are not continuous at the boundary, as opposed to a real life situation. The boundary in length? Yeah, in the natural environment. So how can you be so sure to infer a fracture like that in a core, which is of a finite size, as something that resembles two of the natural environments? That's a very good question. Thank you for asking that. It is absolutely the case that I cannot be sure. Even the example I had of two cores from just centimeters away from each other behaved differently. But I think physically that the one conclusion I feel confident about in terms of upscaling is this one, that this stratification, if flow is going perpendicular to the strata, then there is a limit to the extent to which the permeability can evolve. That's one I'm confident of in terms of upscaling. And the other one is the formation of channels and the permeability evolution increasing. So if you have a mineralogically homogeneous rock for very long length scales, which is unlikely, then conceivably, this could keep going. But again, that's just very rare. And it would be much more rare in a rock that would act as a cap rock. So that's why I feel confident. Yeah. How long would the permeability sort of flow? Sort of, I'm worried that with the kliplotic movement, would you expect canonical shank reactants to it? Do you say that last bit again? Would the kliplotic movement expect canonical shank reactants to stop there? Did we sound the right sort of line? Maybe. It's not going to control the permeability. Yeah. So the question is, well, two questions. One is how long did we do these experiments? They were days. The longest one we did was two to three weeks, I think. And then the question is, would cation exchange with the kli particles be significant? And yeah. If you have a pomegranate collection. What? If you have pomegranate collection. So for example, if you're exchanging pomegranate solution in broad, and if the solution is pomegranate. I guess I don't know the answer to that. I just would suspect it wouldn't have a significant effect on permeability, even if that happens. So on the topic of EoR, for the CO2 that's emerging from the ions, for those already pressurized, it's more readily useful for injecting of the ground compared to those from natural gas wells. So in trying to provide a sense of supply of this, do you think this kind of perpetuates its reliance on fossil fuels? I think our reliance. So what I said is we have a reliance on fossil fuels right now. And this time in the future, when we don't, is far off because of what this comment about the fleet of power plants is the youngest it's ever been in the world. And so yep, there is a reliance on fossil fuels. It exists. So let's add CCS to it, given that that exists, and that's not going away. So I don't see it the other way that CCS is going to perpetuate that. So that's the depths that you're doing. That's just on the strata horizontal, or sometimes with a bend and a point box? That's a good point. We have focused on flow perpendicular to the strata, which I think is the most common case. But you're right, there could be folding, and then I don't know the answer. One real quickie is the depth. Do these factors, did you have a chance to look at the possible? Obviously pressure is going to be different. The marginal cost of drilling may not be constant. It might go down, and so the incentive might be to keep going deeper, which would have positive effects on where we want to go. Yeah, yep. I had the fortune of working with someone who looked at the economics of that. Deeper wells are more expensive, but the containment security is more significant. And the economics of that are going to depend on the value of the carbon and how reliably you have to store it, which may change now. But I think that people who have done those analyses, at least the analyses that I saw, which were done for the Michigan basin, which is one of the deepest in North America, that it is better to go as deep as possible because of the number of traps. The youthfulness of the current fleet is primarily due to China and India, correct? That's not difficult. Yeah, yeah, yeah. How linear is the rate of channel formation with the differential pressure gradient, i.e. if you are able to spread things out more, does that cut down on the pressure gradient? You mean, oh, yeah, so if the pressure gradient is not as large? The vertical pressure gradient in terms of channel formation. Yeah, so we have done simulations like that, and it slows everything down predictably. Slowing down is important in the sense that I had one student who did large-scale simulations. Like imagine if this process is happening over 100 meters, like maybe the thickness of a cap rock. In those simulations, you end up with decades before permeability breakthrough happens, before this happens. And so when that happens is important because if the pressure driving force is gone, meaning if you've injected for 30 years and it would take 50 years before breakthrough happens, then that means that it's not a problem. There's a lot more trapped. Pardon me? There is a lot more CO2 trapped at that point when breakthrough occurs. Well, I'm talking about what I'm calling breakthrough occurs. That's when you have a high flow path leak. And my point is that if the pressure is more disperse than the driving force, forcing that acidic fluid is not so significant, then this process may happen, but it may take decades to happen, so forget about it. It's not going to happen. And when it does, it will be a lot slower. Yep, exactly. Yep. Thank you. Thank you. Thank you very much.