Interviewer: How did you get involved in geologic sequestration?
NEERAJ: That’s an interesting question because I’ve been involved in this since about the mid 1990s and in a sense this started with the work I’d done for my PhD research at Ohio State University. At that time CO2 sequestration was not really a scientific research field but we had looked at these deep geologic formations and asked how does the fluid flow in these formations, and specifically we were looking at the effect of increasing salinity and density as you go deeper in the flow field. The reason for that research was, in the applied sense, that these formations are still used for injection of industrial wastes for waste disposal. So we wanted to better understand what is the regional flow system and the regional behavior in fluids in these formations across the Midwest. I had done a computer model for the entire system all the way from Illinois in to Pennsylvania. Some of our project managers at the Department of Energy (DOE) were aware of that research and they approached us to see if they could use my PhD work to look at the process of CO2 sequestration. That was back in the mid-1990s when this program was just starting at DOE and since then we have been fortunate enough to keep working on this technology and growing our participation in it along with a growing program of the government and the industry.
Interviewer: Can you tell me what exactly is sequestration?
NEERAJ: Sequestration, which we call it CCS (which stands for carbon capture and sequestration or carbon capture and geologic storage) is when you take emissions from power plants or other sources of emissions, such as oil refineries and industrial sources, and you can purify those emissions so that you are left with a pure carbon dioxide that can be compressed and then injected using the deep wells, just like you produce oil and gas from these deep wells. Instead of pulling fluids out from these wells, you are taking the CO2 and putting it back in these deep wells for storage. The key requirement for this is that you need formations that can accept these fluids, like sandstone with high permeability and porosity. And you need a containment of cap rock which can be used to keep the injected fluid in the deep subsurface, so it doesn’t leak out.
Interviewer: How do you capture the carbon dioxide? It must be really hard to do.
NEERAJ: Yes, it is. It’s not difficult in the sense that some of the processes are well known chemical and physical processes that can be used in industry or other types of separations. When you have, for example, a fuel gas coming from a power plant, it may have anywhere from 10 to 15 percent carbon dioxide in it. The rest of the material is nitrogen. And what you need to do is -- you don’t want to inject all of that material into the ground because nitrogen is a harmful gas. So, you use chemical processes, such as what is called an amine-capture in some cases, a solution of amines which absorb the carbon dioxide from the flue gas and let the nitrogen go out, so that gives a pure, purified stream of carbon dioxide so that you are injecting only one-sixth of one-tenth of the fuel gas instead of the entire amount into the deep underground.
Interviewer: The emissions that I see coming out of smokestacks, obviously those are gases, so are you capturing just the CO2 in gas form and putting it underground?
NEERAJ: First of all, the emissions you see coming out of the cooling towers for example, that is really just steam; that is not even CO2. But the smokestacks that do have emissions, yes, once you capture the CO2, from that, you have to mix in a gas bomb, but for injection you have to compress it so that it becomes much more dense. It’s almost like the density of oil on water. It’s lighter than water but much heavier than the gas type of CO2. And that way it’s a highly compressed form and you can put a lot more mass, or amount of C02, in the same volume of underground.
Interviewer: So you got the gas captured in this oil-like state. What do you do with it then? What happens next?
NEERAJ: After capturing it and compressing it you may need a pipeline depending on far your storage reservoir is compared to the emissions sources. Sometimes the ideal situation is that you don’t need a very long pipeline, that you can co-locate your emissions sources in the area where you have good geologic formations for storage. But eventually it is understood that you will need to have network of pipelines that can take away large amounts of CO2 from the producing area and distribute it into the storage areas based on how far those areas might be.. So you need pipelines before you can inject it into a well field.
Interviewer: The pipeline coming out of the power plant -- you just put it a few feet in the ground and let the CO2 go there?
NEERAJ: No, once you have your pipeline and you have taken the CO2 to an ideal storage location which has been screened and characterized by drilling of the wells and testing of the rock formations, you will put it in these wells. And these wells are not just a few inches or a few hundred feet deep. A typical well for CO2 storage would be approximately at least 2,500 feet deep or 800 meters deep, depending on what the formation pressure is, because as you go deeper in the earth, the pressure increases. And at about that depth, the pressure is high enough that when you inject CO2 it will stay in that liquid-like form, what we call the supercritical CO2, as opposed to a gaseous CO2, a gas-based CO2, which is more mobile. That is why you need these formations to be deeper and of course that also means that you have more containment and less likelihood of the gas to leak out from the storage. So, formations we have looked at range anywhere from maybe 2,500 feet to as deep as 10,000 feet or deeper.
Interviewer: Would you have to go as far down if pressure were not an issue?
NEERAJ: If pressure wasn’t an issue and you had an ideal storage room and a good cap rock, yes, maybe you could put it on a somewhat shallower formation. Another thing you want to make sure of is that the CO2 that you inject is deeper than any freshwater sources of groundwater. As we go deeper, the water becomes more and more saline and you end up with brine, which is very dense and it has salinity even much higher than the seawater. That way it is not useable for drinking or any other industrial uses. Another criteria, of course, is that you want to make sure that if you have other oil and gas producing zones at shallow depth that you don’t interfere with the production of oil and gas from those.
Interviewer: Can you talk about the relationship between cap rock and porous rocks. What is the relationship and why are they important for the sequestration?
NEERAJ: Imagine for example, a sponge or if you have seen a sandstone. If you put a drop of water on some pieces of rock, that water is immediately absorbed. You need those types -- what we call reservoir rocks -- for injection zones, that can absorb carbon dioxide as you inject into the deep well. That carbon dioxide is absorbed and it kind of moves away as you keep on injecting, so you have a plume, or an area of CO2 within your injection zone. Now, as long as it’s going horizontally or laterally within that injection zone, you’re okay. But you do want to make sure it does not move upward vertically into the shallow zone, or into the freshwater zones. To do that, you need other layers of rock which have very low porosity and permeability. So it would be like a piece of marble or a shale type rock where you put a drop of water and it doesn’t absorb very quickly, or not at all. That’s a cap rock and that prevents the leakage of CO2.
Interviewer: Why is a saline reservoir a good candidate for storage?
NEERAJ: You can put carbon dioxide in any reservoir but the key thing is that you want to avoid freshwater reservoirs which are a source of groundwater which is s a precious commodity around the world. Water resources are not easy to find everywhere as they might be in the Midwest, for example. But as you go deeper in the ground, there is more and more dissolved salt in that water, so it becomes more saline. And at some depth, let’s say you have 10,000 parts per million of dissolved cellular salt in that water, or 20,000, or we have as much as 400,000 parts per million. That means 40 percent of the brine is actually salt. That high salinity water is not useable now or in the foreseeable future for any other uses. That is why it can be used for injection. If it were useable for freshwater, drinking water, or industrial uses, then you would not want to use that resource for C02 storage.
Interviewer: What is the relationship between saline and CO2 at a super critical state?
NEERAJ: When you are injecting Co2 in what we call the deep saline formations, which have high salined brine, what happens is that the CO2, does not mix very easily with the saline water; it’s like oil floating on water. It’s the same type of mixing relationship. What happens is that it tends to stay in that formation because it’s lighter in density than the saline water. It will tend to float up but only as high as the cap rock, because it cannot penetrate the cap rock because of the low permeability of the cap rock.So it tends to float up and forms like an inverted cone type lens, depending on the thickness of the reservoir. Some of that CO2 will dissolve in the brine. So you have a CO2 phase which is like the oil phase floating on water and you have some dissolved carbon dioxide, which makes it a carbonic acid type solution. It will reduce the ph a little bit so it will become somewhat acidic, but because it is separate from the shallow zones, it is not a major concern. And in the very long term, some of that dissolved CO2 may react with other minerals in the formation and may form solid phases. But those are very slow, long term reactions.
Interviewer: So how do we put sequestration into practice?
NEERAJ: Well, we have sponsorship from the U.S. Department of Energy and a large number of industrial companies, especially electric companies and oil and gas companies. We have a research program which is looking at what types of reservoir, what types of rocks are present, in, for example, the Midwestern region that could be used for injection. You have to map these formations and know where you can do this safely. Part of that is drilling these deep wells like we’ve seen at the Burger power plant. We’re drilling a deep well. The first phase of that is really looking at the types of rock layers and understanding them properly so we can know where are the suitable injection zones and can we inject safely. What we’re planning to do is do some injection at small scale at this stage, something like maybe up to a few thousand tons of CO2, or more if it’s available, and do testing to understand what happens to CO2 but also check public opinion and build more public confidence in this technology. And by public I also mean the companies and the decision-makers within the company, the policymakers who have to decide on to implement this technology.
Interviewer: Why did you choose the Burger power plant (in Belmont County, Ohio) as a site?
NEERAJ: The Burger plant site was chosen for several reasons. One is that they have a willing host and a sponsor at that site. But also, it’s in an area where we need to understand the geology as well as the sequestration potential and very importantly, we also are planning to have a test for the CO2 capture technology. If that CO2 capture technology is developed in time for our injection testing, we would hope to be able to use that to build what we call an integrated CO2 capture and injection demonstration. That was one of the reasons that it was chosen - it ties in the research on developing new capture technologies with the location at the power plant in an important area where you have a large number of other power plants, and an area where we need to understand the geology better or sequestration potential.
Interviewer: What is the potential for storage at the site that you’re drilling at now?
NEERAJ: That is what we’re trying to find out with drilling. Overall, in the region that we are working in, which is a seven or eight-state Midwestern region, all the way up to New York and Pennsylvania, we have estimated that there is very large storage potential that can take in CO2 for maybe the next many decades or centuries worth of emissions. Now what we have to do is connect that original knowledge to a site-specific understanding of different parts of the region. That’s why we have tests in Michigan. We have a test on the Indiana border, and another one at this public plant, and we’ve also done testing at other locations in region.
Interviewer: What is your goal at the Burger site?
NEERAJ: Our goal at Burger is first and foremost to start building a regional framework with a number of site-specific tests to understand what layers can be used for the geologic storage. Do they have sufficient potential for large scale storage over the long term? And also, to check the safety, along with the injection potential; we have to make sure that we have enough cap rock. So the goal is to understand the geology but also to develop the regional framework and also to estimate how much can you store and how many wells it might take to store that much.
Interviewer: Do you think it’s possible that 100 percent of Burger’s CO2 emissions could be stored underground for the next 100 years?
NEERAJ: It depends on what you mean -- how big an area we have. We don’t know how much we can store in a single well at the site here. That’s why we are doing all this testing now. So, it’s a question not of whether or not you can store it, but how many wells you would need and over how big an area. Those are the key questions and at some stage if it means that you need hundreds of wells for a single power plant, obviously maybe it’s not an ideal site. Or it’s not the most economical site, for example. But if you can do it within a few wells, then it’s probably a good site.
Interviewer: How far along are you to finding out whether Burger is a good site?
NEERAJ: I think we have a fair amount of work to do. We basically started this project this year at Burger, and it’s very important to keep in mind that what they’re doing applies to a wider region; it’s only one data point out of many, many that we will need before we can be confident about this. So, I see this as a very important first step for our long-term program, just like the oil and gas industry. It’s still exploring; it started more than 100 years ago and it’s still finding new reservoirs for oil and gas and producing oil and gas from those reservoirs. It’s the same type of approach as that. You don’t need a century to figure out what you can do, but you do need some more work. We are drilling our first well right now. We hope to be able to test injection potential in this, and I think over the next two years we would have demonstrated and evaluated the sites that have potential in that area. Then we will need to link that with our regional knowledge over time to see what’s possible in the region and only then we will have a better understanding.
Interviewer: How far do you drill down now?
NEERAJ: The drilling started in early January and as of today we are at about 6500 feet depth in this well. Our goal for this particular well is about 8200 feet. There is additional sedimentary thickness below that depth, but with the current rate and the current objectives for the project that is our goal. We would hope that in the future we can drill additional wells that can look at the deeper geology too.
Interviewer: Once you finish drilling you will take some very important samples. What are those samples and why they are so important?
NEERAJ: Drilling is just a means to an end. If we are just drilling a bore hole and not collecting any information as we go along, then after we are done with drilling, it’s a wasted expense, basically. What we do is during the drilling process, we are collecting all the rocks that come up as part of the drilling waste and we keep looking at that to evaluate the formations. At several stages during the drilling we stop and just like you do an MR scan for your medical checkup, or you do some other tests for, ultrasound, in the same way you can send tools down in the bore hole that can take ultrasound images of sonic images of the rocks and around the bore hole. That tells us a lot about the properties of the rocks and which would be good cap rocks and which ones would be good otherwise. The third thing you do is you collect some samples, either at full core or at what we call the sidewall core, where you can turn the tool, and from the side of the bore hole it can collect a one or two inch piece of rock that can be tested for permeability and porosity in the lab.
Interviewer: What is the timeline for this technology -- 20 years away? Five years away?
NEERAJ: Well, if you are looking at a timeline for the technology, all of the components of this technology are already there. If you needed by any chance to implement it very quickly, you could do it. Over the next few years we will keep on building our level of confidence and knowledge in it, and depending on the policy framework, it could be deployed sooner, or we can keep on making more improvements and hopefully reducing the cost over the next five or 10 or 15 years. But the sooner you deploy it, the sooner you can take care of the emissions reductions.
Interviewer: What do you see in the future for geologic sequestration?
NEERAJ: As far as the future application of the geologic sequestration is concerned, a lot will depend on the policy framework and what is the relative cost of this option, related to the other technologies, for meaningful reduction of carbon dioxide emissions. What we could foresee is that if the concerns about climate change remain and become more and more serious, this technology could be applied to a large number of power plants for energy and power production, and also for industrial facilities, like refineries and oil plants and ammonia plants, and steam plants. So in that sense you could foresee a future just like we have right now in infrastructure, with pipelines and refineries and production facilities for oil and gas. You would foresee a future maybe not at the same scale as hundreds of thousands of oil wells but maybe a few thousands or even tens of thousands of these deep wells injecting hundredth of millionth of tons of CO2 into the ground annually around the world. And that would be a significant part of the portfolio for technologies for reducing CO2 emissions.
Interviewer: Why should the person on the street care about funding for this project and whether the research continues?
NEERAJ: It depends if the person on the street is concerned about the climate change issues and is affected by the climate change issues. If funding stops, you have to see what options are there to take care of the climate condition. In that sense I keep coming back to the policy framework that makes this thing happen.