 And today, we are here to learn about methane hydrates. This session on methane hydrates is part of our public education series on frontier energy, which aims to explore innovations on the edge of mainstream adoption, focusing on technological opportunities and the role of public and private sectors in the innovation process. The methane hydrate is molecules of natural gas trapped in an ice-like cage of water molecules. If methane hydrate is either warmed or depressurized, it will revert back to water and natural gas. It's from all the DOE and Jogmic websites, and that's how much I know about the chemistry side. Anyway, that's why I'm here to be educated. While global resource estimates vary considerably, the energy content of methane hydrates, a methane-occurring hydrate form is immense, possibly exceeding the combined energy content of all other known fossil fuels. Also, future production volumes are speculative at this point because methane production from hydrate is only at the experimental stage today. But its successful, large-scale production can mean a game changer for many countries with substantial methane hydrate resources and beyond to the global energy system potentially. We have the two leading methane hydrate technology experts today to help us better understand what methane hydrate is, its resource potential, where we are in terms of global R&D efforts, particularly with a particular focus on the US and Japanese efforts. And what maybe we can also talk about some of the environmental implications that the methane hydrate production may have. From you to my left is Ray Boswell. He's the Technology Manager for Methane Hydrates with the National Energy Technology Lab. And to his right is Takami Kawamoto. He's the Deputy Director General of the Methane Hydrate Research and Development Group with the Japan Oil, Gas and Metals National Corporation, also known as Jogmec, based in Tokyo, Japan. So, without further ado, and I believe that the handout has more extensive narrative and impressive bios on the two gentlemen. So, I invite you to look at them for further information, but without further ado, Ray, please help educate us. Thank you very much, Jane. It's a pleasure to be here to talk about gas hydrates. It's a fascinating subject. It's one that didn't exist in anybody's mind when I was in school, which was only a couple of decades ago. And now it's getting a lot of attention. In the last decade, nations have launched very sincere, comprehensive, scientific expeditions to appraise gas hydrate resource potential. And each one of these expeditions has returned positive results, such that each country is continuing to invest and study this issue. So, it's accelerating rapidly. So, Jane mentioned this a little bit, but I'll just go a little over what gas hydrate is. It's a naturally occurring solid substance that will form spontaneously whenever you put a gas molecule of the appropriate size in the presence of water under certain specific pressure and temperature conditions. Water is ubiquitous, and in nature, methane turns out to be fairly ubiquitous as well. So, 100 years ago, people thought we could only make hydrates in the lab. It was only in the late 60s that people began to realize that the conditions that would create hydrate would occur in nature, and it wasn't until the 80s that anybody actually saw one. So, it's a relatively new science. But now that we've gotten our hand around it, it's beginning to change the way we think about a lot of things that involve carbon organic, carbon cycle, energy, et cetera. People ask about the gas. It is the same methane gas that is in natural gas. In most gas hydrates, the gas is predominantly methane. A lot of times it's 99% methane. That methane is generated by microbial processes or thermogenic processes. The hydrate doesn't care. Where can hydrate occur? Where do you get these unique conditions whereby you're putting something under a lot of pressure but you're also not heating it up because pressure and temperature in nature generally tend to increase together. It happens whenever you have some thick overburden that's cold, either permafrost or deep water. And depending on where you are in the globe, it's 300 to 500 meters of water is enough to depress the thermal gradient enough so that gas hydrate can form. So, you can see these charts, the fairly complex charts. The red chart is the gas hydrate stability boundary to your left of those gas hydrate is stable. The blue line is the typical pressure change with depth and hydrate occurs in these conditions. So, in about 800 feet of water, you might get 200 foot thick stability zone. Deeper water, the stability zone gets thicker yet. But that's where gas hydrate can occur. That's not where it necessarily does occur. So, people have attempted to create models to understand where is the organic matter, what is the temperature and pressure like in different places to generate the methane that would create hydrate and make these global models to try to estimate how much hydrate exists. And a variety of approaches, it's a big area. If you assume 0.5% of the available space is filled with hydrate, you'll get a very different answer than someone who believes that 2% is filled with hydrate, even though both numbers are still very low, they'll be different by factor of four. And that's what we're getting. The numbers that come out of the models have one thing in common, they have a lot of zeros. But these numbers, we talk about them in trillions of cubic feet. So, the low order estimates are 100,000 trillion cubic feet of methane in place in hydrate form on the globe. The larger number is up to four million. I think a lot of people would put the number somewhere, of course, in between those. If you take some number that's in between though, hydrate represents a substantial portion of all the potentially mobile organic carbon on the planet. And this is something that wasn't known 20 years ago. And so this has a lot of implications, right? And the major implications of hydrates are for the safety of operations offshore where you're trying to get at something and you have to go through a zone of gas hydrate to get to it, the implications for the global environment. What does it mean for long-term carbon cycling, short-term responses of the geosphere to climate change, the development of particular chemo-synthetic biological communities that feed on methane, the stability of the continental shelves. But what we're here to talk about primarily is what it means for the energy resource. What its implications are for energy resources in the future. So to take that big number with all the zeros and put it into a context of what might actually be a feasible reality for gas hydrate as an energy source, I think one of the first things to appreciate is that not all gas hydrates are the same. They vary dramatically in their form and their concentration. And the primary thing that differentiates these forms is the host sediment in which the hydrate accumulates. So we see up here on the images, you can see in the upper right, there's hydrate in mud. Hydrate in mud tends to be concentrated at very low saturations, but over large areas. On the bottom right, there's a sea floor mound. This is where methane has escaped to the sea floor and formed a solid mass of hydrate. These things can be the size of cars to houses littered around the sea floor. But the interesting ones for gas hydrate energy are the ones where hydrate forms within the pore space of a coarse grain sediment, a sand or a coarse silt. These sand-hosted hydrates have resource, have methane that's concentrated to a high degree. 50, 60, 70, 80% of the pore space can be filled with hydrate. This is because they're in a host media that is amenable to letting the gas in the water mix and assemble the hydrate. That is also, that same quality is what also makes them most amenable to the proven production concepts. So the most promising one, which Commode Assign will talk about in a minute, I believe, is the depressurization technique. And if you have a reservoir that is porous and permeable, you have the ability to transmit pressure through it. A lot more easily than through something that is quite tight. So these sand-hosted hydrates are the initial resource target. So first question then is how do you go about finding them? And the basic answer to that question is by using the same approaches that have guided conventional exploration for hydrocarbons for the last century. With one thing, you have to tailor it for gas hydrates by making sure you're in the gas hydrate stability zone. So in this diagram, geophysicists have determined where the approximate base of the gas hydrate stability zone is. And they're looking in, if you're looking for hydrates, you're looking in the area between that and the seafloor for things that have geophysical indications of gas hydrate. So that's what we call direct detection. That's when you see the hydrate directly because of how it has changed the physical properties of the sediment that it's in. This will be a risky proposition as all geologic exploration is. And you have to, you can mitigate the risks or the uncertainties by also looking to see that you have a supply of gas. There's an evidence of here. And you have migration pathways that connect the supply of gas to the reservoirs that you're looking at. And that's the way exploration is done for conventional oil and gas as well. So there's no black box, there's nothing uniquely different about hydrate from an exploration concept. So I'm going to give you a few examples of gas hydrate exploration from the major sites around the world that you're going to hear more about. First one is Nankai Trough, Japan. I really can't do this without standing and pointing. Is that okay? Yep. Can everyone hear him? Well, actually, we might. Well, maybe I can do it without standing at point. The judge just moved down this. Yeah, that's okay. Why do you use this? I'll break the screen. So geophysics can be kind of complicated, but also it can be really pretty simple. This is on reflection seismic typical response you get from the seafloor. And that just means you've gone from something that transmits sound waves quite readily to something, I mean, quite slowly to something that transmits them quite more readily, or something that we call slow to something fast or hard. You're going from the water to the sediment, and you get this big reflection. Whenever you hit something hard, you get a reflection that looks like that, and hydrate makes the sediment somewhat hard. And it's kind of anomalous amongst the things that can exist in that part of the sediment column that do that. So whenever you see something that looks kind of like the seafloor below the seafloor, it's potentially a gas hydrate. And in this example, you can see all these reflections here. That look just like the seafloor. So that is combined with the standard geophysical analysis of where do I think reservoir quality rocks are with the pressure temperature regime of where do I think the stability zone is, and you've got a hydrate prospect. And this is a big, thick sand that's impinging into the base of the gas hydra stability zone. And these have been drilled 20, 30, 40 times offshore in Japan, and found hydrate pretty much every time, right? Okay, another example from the Gulf of Mexico. Here, we've got maps made by the Bureau of Ocean Energy Management of various geophysical indicators of gas hydrate. All of them could be a gas hydrate, could not be a gas hydrate. They need to be tested. Industry consortium with DOE went to three of these sites. I'm gonna show you an example from one. Drilled seven wells, we found hydrate in sand reservoirs in four of the seven wells. Whoops. And here is an example of one of these things that's slow changing to hard as you move into the gas hydrate stability zone. So this is a thin layer of reservoir quality sand that's inclined in going into the gas hydrate stability zone. And nature is changing right there because above the sand is filled with hydrate and below it's filled with gas. If you make a map on this plane, it looks like this, where you can see the sand body full of gas below and full of hydrate above. This was drilled and confirmed to be gas hydrate. Oh, that's the wrong down button. The third example, the North Slope of Alaska. Hydrates also exist underneath permafrost. Modeling over several, many years by the USGS identified where the hydrate stability zones existed and where hydrate was likely to occur. Detailed geophysical investigations delineated specific prospects. And in 2007, we went in and drilled one of those and there was hydrate there. And this was the hydrate. We found 100 feet of hydrate in sand there. So the basic message here is that thus far it seems that there is a fairly viable way of delineating gas hydrate from standard data and finding it. So how much is there? It's kind of the big question. Based on some of this work in Alaska and elsewhere, USGS has assessed 85 TCF of technically recoverable resources on the Alaska North Slope. That is gas hydrate that they believe is recoverable with the technology that exists today. It doesn't mean it's economic today. In the Gulf of Mexico, the Bureau of Ocean Energy Management has assessed 21,000 TCF in place total, 6,000 of that in place in this types of sand reservoirs and at the high concentrations that make them resource targets. That's 6,700 TCF compared with our annual consumption of 20 or 30 TCF. TCF of hydrate or of methane? TCF of methane. At surface conditions. They've recently conducted an investigation on the Atlantic margin where they have large areas that they believe are prone to sand in the gas hydra stability zone and potentially even larger volumes existing there. There's been one attempt to try to estimate how much gas in place exists in sand-rich reservoirs globally and that was done by Arthur Johnson of Hydrate Energy International a few years ago. And he came up with a cumulative total number of around 43,000 TCF. And it's distributed fairly equitably around the globe. This is his effort to try to determine where in that stability zone are you likely to have the reservoirs that allow hydrate to accumulate to the concentrations that make it a feasible exploration of production target. So I've got two slides left. And one of the important things here is when you're talking to someone about hydrates, make sure you know what they mean when they use the word resource. Some people will talk about the hydrate resource and we talk about the in-place number which is 100,000, 4 million trillion. It's a number that's really not relevant to what is the energy potential of hydrate discussion. What we need to talk about is what is the technically recoverable fraction? And we've begun to move away from those astronomical numbers and zero in on that by zeroing in on that portion of the hydrate resource that is in sand reservoirs. And that's been done in just a few places on the globe where it's been enough data to support it. And those numbers suggest that the recoverable resource is going to be somewhere likely in the tens of thousands potentially. But that's technically recoverable. That is not necessarily economically recoverable. And whether it's economically recoverable not depends on just what technologies are used to produce it. So sum up this first part. The gas hydrate in-place resources are large but poorly constrained and not entirely relevant to this particular question. The occurrences are widespread and variable. Sand hosted hydrates are the ones that are the most relevant to the resource question. And they have been found both offshore and in Arctic settings. We're gonna estimate the resource on the order of 10,000 TCF now acknowledging that only a few areas have been studied in detail. And we know that we have existing exploration methods that will seem to give us positive results. So I think with that I am done. Great. Thank you, sir, for this. Thank you. Great, thanks so much, right? And Mr. Kamleto, your turn. Okay, good afternoon, ladies and gentlemen. As Jane Kandrie introduced me, my name is Takami Kamleto. I'm working for Jogmec. And as you may know that Jogmec has been promoting Japan's methane hydrate research and development program. We have conducted the first offshore project test in March last year based on this program. Today I'll briefly talk about the update of the methane hydrate R&D activities in Japan. It's a kind of, Ray sort of introduced a quite pure scientific thing, but I can kind of introduce a sort of a more development side of the methane hydrate things. This one? I skipped a couple of them. This is already explained by, right? Yep. In this slide, I'd like to explain the Japan's methane hydrate research and development program itself, which was announced by Mitie in 2001. This program is comprised of three phases. Phase one started in 2001 and finished in 2008. In this phase, onshore production tests were conducted twice at a permafrost area in Canada. Regarding inside of Japan, we conducted studies relating to resource assessment in eastern Nankai Trath. I will talk about these activities in phase one later on. In phase two started in 2009 and is supposed to finish by 2015. We are in this phase right now. We have conducted the first offshore production test at eastern Nankai Trath. In this phase, we are exploring the opportunity to conduct onshore production test as well. The last part is phase three. Phase three is scheduled to start from 2016. This phase is planned to establish the technological platform for the future commercial production. We have just started the preparation for the next offshore production test in phase three. And from now on, I'd like to touch upon our activities in phase one of the program worldwide. In 2002, we conducted the first onshore production test at Marek site at Mackenji Delta, which is a permafrost area in Northwest Territories in Canada. We conducted the production test by applying a heated water-circulated method. As Ray explained that when you want to dissolve that methane hydrate, either you should raise the temperature or reduce the pressure. So this time we just raise the temperature at the site. We successfully produced the methane gas through dissociation of methane hydrate, although production volume was not so big. We however revealed that heat water circulation method does not have enough energy efficiency through this test. In 2007 and 2008, we conducted the second onshore production test at same site at Marek in Canada again. We applied a depressurization method in this time and produced 13,000 cubic meter of methane gas in six days. We could verify the effectiveness of the depressurization method through the second test. That is why we decided to use this method in the first offshore production test in Japan. While we conducted the onshore production test in Canada, we are also conducting a resource assessment of methane hydrate inside Japan. We picked up the Eastern Nankai Trough as a model area for our research. This is a map for Eastern Nankai Trough. After the program started, two dimensional seismic surveys and 3D seismic surveys are conducted. Based on the interpretation of the seismic surveys, we conducted the campaigns of drinks and the callings in 2004 named Toka-Yoki Kumanonada Exploratory Drinks. This figure shows 2D high-resolution seismic lines by pink line and also the brown lines. And areas of 3D seismic surveys by yellow rectangles. And we drilled 16 points of the exploratory drilling in 2004, that's showed by the red circle. And this is a result of our resource assessment in Eastern Nankai Trough. It's kind of detailed, but I explained. We introduced the concept of methane hydrate concentrated zone, where methane hydrate is concentrated in 3D layers as similar manner to the conventional natural gas fields. We confirmed more than 10 methane hydrate concentrated zone at the Eastern Nankai Trough. Pink part in this table shows a evaluated resource amount of methane hydrate concentrated zone, or MHCZ. Yellow line shows a resource amount of MECCs, which are confirmed by exploratory drinks. And the green line shows a resource amount of MHCZ, which are evaluated by seismic surveys and which are not confirmed by drilling. The addition of these two lines will give you total resource amount of MHCZ, which is equivalent to approximately 20 TCF of methane gas in place as a mean value. Light blue parts show the resource amount of methane hydrate bearing layers other than methane hydrate concentrated zone. The resource amount other than the concentration zone was evaluated by a calculation, applying data acquired where we do not identify MHCZ by drillings. In total, we estimated resource amount in place is equivalent to approximately 40 TCF of methane gas in place as a mean value in the Eastern Nankai Trough as a whole. At the end of phase one, we revised the map of methane hydrate distribution in Japan. There are differences in color, depending on the probabilities of methane hydrate distribution. Red color represents area where concentrated zone are confirmed, which is Eastern Nankai Trough, as you see. Blue represents area where concentrations are suggested. Green represents area where concentrations are not suggested. Light blue represents area where we only have limited data to identify the concentration. We estimate these probabilities of methane hydrate distributions, mainly utilizing BSR occurrence. They did not explain BSR much, but the BSR stands for bottom simulating reflector, which appears parallel to the C-floor when the methane hydrate exists. I'll explain that later. And the total BSR area is 120,000 square kilometers in Japan. We could identify BSR occurrence by utilizing data from past seismic surveys. From here, I would like to talk about the first offshore production test conducted in phase two. We selected one of the concentrated zones identified in phase one as a target of the test. This is our red circle. Yellow area shows the BSR distributions. And the site was selected among more than 10 concentrated zones based on the overall evaluation by comparing various aspects. This is 50 to 70 kilometer of the coast of main island of Japan. And this shows the seismic profile of the test location. It may be difficult to see the light blue lines. Well, this is BSR, bottom simulating reflector. This is parallel to this C-floor, because that condition of the temperature and pressure is the same as the other sort of show this. And this lies top of the gas hydrate concentrate zone. So we have concentrated, sorry, the methanhydrate concentrate zone here. So we targeted this area for the production. And this is a horizontal view of the total target area. This is origin from the sort of, how do you say, it's made by the sort of a current, how do you say, I forget, sorry. And this is vertically exaggerated figure so that real scale is like that, quite shallow formation. And this slide shows the layout of the wells for the first production test on the right side. We drilled four wells, including one production well, P well, two monitoring wells, MC well, and the MT1 well, and one calling well, C well. We drilled the two monitoring wells adjacent to the production well in around 20 meter distance, very near. Figure on the right-hand side show the layout of the drilled wells. Picture on the left-hand side shows the images, image drawings of the flotests conducted the Daini-Atsumi Noor in the Eastern Nankai Trough. The C depth is approximately 1,000 meter and depth shows the methane-hydrate bearing layers at around 300 meter from the sea floor. And regarding the P well, we used the drill ship and riser pipe for drilling and the flotests. After drilling and completion by Global Park, we learned borehole assembly, specially designed and manufactured for the flotests. We decided to apply deep-pressurization method to this flotest. We pump out the water inside riser pipe so that we are able to reduce the pressure at the borehole. We have drilled these two monitoring wells in order to monitor the changes in temperature in 20 meter distance aiming to capture the dissociation of the methane-hydrate layers there. If the, since that the methane-hydrate is, when that dissociates, that reduce the temperature. So we have successfully monitored the temperature drops at these wells. And now I'd like to show the result of the flotest. We started operations on January 28th and ended them on April 1st. In the early morning of March 12th, we finished learning borehole assembly and the installed packer. We began flotest at 5.40 AM with decreasing the pressure of borehole by ESP pump. We confirmed gas production from methane-hydrate layers at 9.30 AM. At around 10 o'clock, we needed the flaring. We continued production after flaring by March 18th when we had an unexpected sand production on board. We decided to end the flotest because of the sand production and the water status, sorry, the weather status where we had expected very bad in the night of the day, which might make us to disconnect the drill ship from the P-well. That graph showed the overall result of the production test. Red line showed the gas production rate. And blue line showed the water production for about six days. And as you may see, that we achieved the fairly stable production for six days. Green line shows the pressure at ESP pump intake. As a result, we were in production for six days. Cumulative gas production was 120,000 cubic meter and average daily gas production was 220,000 cubic meter. This is the last slide. This slide shows the process toward the commercialization of the methane-hydrate in the latest basic plan on ocean policy approved by Japan's cabinet in April 2013. This plan is basically extended the current methane-hydrate R&D program and additionally states that by 2027, a project led by private companies may start. From 2013 to 2015, where we are now, we conducted the first offshore production test here. Oh, sorry. First offshore production test here. And analyzing the test result and overcoming technological issues as a preparation for the next offshore production test. This plan also states that we are supposed to conduct a middle to long-term production test onshore. Yeah, it's the same. We are now searching for the opportunities to conduct such onshore production tests. And I think that Alaska may be one of the options to realize this specific goal. From 2016 to 2018, we are also supposed to conduct the next offshore production test. For your information, in this plan, research on seabed type, we are targeting at the sand formation type. But seabed type is also included in this plan at the first time. We believe that we need to conduct the next production test mainly for the purpose of verifying our countermeasures against the technological issues, such as sand production, which terminated our first production test last year. Thank you very much for your attention. I welcome your questions. Thank you very much, both of you, It was a wonderful sort of division of labor. The first way illustrated more of a scientific side of the methane hydrates. And then, of course, the technology side of the story. And if I may, I'd like to start asking some questions. So this will really display my eagerness on all these technology issues. One of your slides does talk about, I mean, you did talk about how obviously we need to differentiate the technical, recoverable resources and, of course, the economically recoverable resource, not necessarily, I'm sorry, resource, et cetera. So it depends, the economics of it obviously is impacted by production technology. So far, did I get it right? So far, I guess, what we or maybe the US is targeting is the sandwich. And that also uses the proven production concept. Is it how you, did I? So that means very much sort of conventional oil gas. Is it right? Yeah, OK, so that's OK. So there's no conception here of mining. It's dredging it, this sort of thing. It's the type of accumulations that can be produced by drilling wells with standard existing equipment. So that's very much that's applicable to the sandwich. And that's why we're focusing on that sort of the one of the lower hanging, I mean, well, if there is. If there is, exactly. But so once we start going beyond that, then what are some of the production concepts that you need to start considering? I'd like to crack this nut first. OK, all right. So maybe five to 10 years, we can have another session. OK, the other thing that I wanted to ask you is that the map shows that there are a lot of potentials around the world. And if I'm not mistaken that the US government has engaged several countries besides Japan, and also probably besides Canada, I guess there are some efforts or experiments with the Indian government and some of China, Korea, and such. If you can tell us a little more about where they're at and how are the US expertise is bringing to the table vis-a-vis where they're at. And also, you can probably tell us about how our efforts complement what the Japanese are doing as well, that would be great. OK, well first, the Department of Energy has agreements at the departmental level to promote gas hydrate science with Japan, Korea, and India. And we collaborated quite extensively with many other nations as well. But those are the ones that have large, well-funded exploration programs. We're all indebted very much to the Japanese program, which has certainly been at the forefront of this effort. They were the first to show gas hydrate existed in sand reservoirs in the marine environment. And then, as Kawamoto-san just showed us, they made that substantial effort and investment of demonstrating production from the marine environment. Those are certainly major. India, Korea have both launched. Korea has launched two expeditions to assess gas hydrate occurrence. Korea has. India has launched one, is about to do a second. Both of them have the same general plan of getting a feel for what exists in their waters and to find a site to attempt a production test. So what is really most needed now is a production test that's of sufficient duration to allow modelers and engineers to begin to predict how these things will behave over extended time frames. They will do that with six days of data. If six days of data is all you have to give them. But big error bars on the results. So Kawamoto-san talked about an onshore test of mid or to long term duration. And we think that means 12 months or a year before you really get to separate all the noise down there out of how the reservoir is responding. Is that a more follow-up question? Do you have more about? I have a question about what we've learned from the six days of production, which seems to me very important to this discussion. May I ask it? OK. I am interested, Mr. Kawamoto, in the gas-water ratios you encountered. If you can draw a conclusion. And I'm interested, Mr. Boswell, in the theoretical gas-water ratios that you would get in producing this kind of sandstone reservoir. That's one. Number two, I'm curious whether you have yet tested the water part to see whether, from an environmental point of view, say Japanese environmental ocean protection rules, you could discharge the water directly into the ocean or you'd have to treat it. But why don't you start with the first, just the physical. You've got a ratio of methane to water in the hydrate in the pore space. And then you produce it by pressure drop. Sounds to me analogous to what we do with coal, seam, methane, and whatnot. But what kind of ratios do you run? And do you expect the ratios to change as you go along? Regarding that gas-water ratio, as I show you by graph, as you may see that gas production is, as I explained, like 20,000 cubic meters per day. And water, as you may see that, or this is water production, so around 200 cubic meters per day. So that means that 1 to 100 is. 1 to 200. No, 1 to 100. 1 to 100. Cubic meters? Yes, that's the ratio is like that in terms of cubic meters. And we haven't kind of quite well understand yet. But in theory, that sort of ratio has to be kind of, how should I say? Smaller, I mean, more water production has to be there. So we don't know something in that. So we are now analyzing why we got this gas production ratio right now. That's what we are doing right now. You expected more water? Yeah. So it's possible that the water is staying down in the reservoir? Yeah, that's one of the, yeah. And that's a petroleum engineering point of view. That's not very, that may not be very encouraging, because it might block the flow of methane along the way. Right. But there's work to be done. OK. And the next question regarding that water kind of sort of a quality of the water, produce water. Actually, we can discharge part of that water into the, dump into the sea water. We just received sort of a certificate from our government organization that passed that test. So we discharged that. Thank you very much. Speaking on the environmental sort of implications or the category of implications, I wanted to ask if there's already sort of discussion that's happening either within the scientific community that looks at methane-hydrate production or maybe with some of the, I mean, generally, what's the potential, the methane leakage challenge associated with sort of a robust production down the road? I don't know if that's more of a policy question, but for now I'm interested if there is some sort of modeling or would it be different from many other ways that the mythings could be released into the atmosphere? Yeah, methane-hydrate, as I mentioned, its abundance in nature has led to a lot of study. And one of the issues is, is it a potential respondent to climate change? And there certainly is a potential for that. Those hydrates are the ones that are more closely coupled to the environment. They're the ones that exist very near the surface or the shallow, up-dip end of the stability zone. Whereas the ones that are the most promising for production are the ones that are most decoupled from the environment, more deeply buried. The more deeply buried they are, the warmer they are, the more competent what they're sitting in is, and the more separation you have from the seafloor. So there isn't a real good connection between those two types of hydrates. They're very different hydrates respond to very different things. Disarm a methane release by producing it, and you can't exacerbate a methane release by producing it. They're just two entirely different things. Another issue is, people think because hydrate needs to be destabilized, that it's somehow unstable. And that just basically, so those pictures you saw that I talked, that's hydrate just sort of sitting there, it's way out of its stability zone. You need to be minus ADC for hydrate to be stable at the surface. And it's just slowly melting like an ice cube taken out of your freezer and put it on the table, that they don't explode when they are thermodynamically unstable, which means they can't persist in that state, in that condition, but it's not a catastrophic sort of transformation. Hydrate wells will be very shallow and they're low pressure by nature. And they have to be pushed out of their stability zone to produce. And if you stop pushing on them, they respond back. Blowouts, uncontrolled, runaway dissociation is something we can't figure out how it's possible. Am I okay saying that? Yes, that's fine. Thank you, Grape. But when we conduct this production test, that we also have a concern on this environment. So we put a couple of monitoring systems there. One is a methane leakage detector, and the other one is to detect the subsidence of that sea floor. We cannot, I cannot say anything on that, but since we have a really concern on that environment, we try to sort of collect lots of data from our production test. It's a very short period of time, but we really got quite good data, we believe. So we can, like I explained at the later days. And regarding that the blowouts, even though we put the BOP here, but this is just, we have to follow the Japanese industry law. So that's why we put the BOPs. But there are lots of sort of discussions there, but well, in some way we may have to have a BOPs because we may have a kind of unexpected gas kick or something like that. So naturally, as they explained that, that is quite a stable thing. So even though if it's collapsed by accident, then well, the dissociation or the resolution will naturally stop when you have a water coming into the well. Yes, I don't want to suggest that there are no issues. There are certainly a lot of issues. This is not very well known. It's only been tested a little bit. It is shallow that it is producing from something that once you take the hydrate out is unconsolidated. So there are issues with things such as seafloor subsidence from long-term production. And these are all things that have to be monitored and measured and then engineering solutions either developed or it won't work. On this slide, Mr. anything you want? Jeff Epping with NHSLOC, two-part question. Given the aspect ratio of these things, do you think? Jeff Epping with NHSLOC, given the aspect ratio of these reservoirs, do you think ultimately they'll be amenable to horizontal drilling for exploitation? And then Ray and your economics, what price did you use for discriminating economics from technically recoverable? Or just some indicative economics. How difficult is it economically to exploit these things? My standard answer to that is to assess economics, you need to know two things. You need to know what the production profile is going to be over a period of time. And you need to know how much you have to invest to get that production profile. We don't know either one of those things. Well enough to make an estimate. So I think the answer to your question is that it's assumed the technically recoverable is what could be produced but we don't have a bar with which to slice from that what's economic at present. My answer to your question is that we don't know yet about the nature of the methyl hydrate yet through this short term period of time. So we definitely have to kind of conduct a longer term production test. But as I explained to you that we also have technological issues like sand production. So we have to stop those sand production first and then we have to continue to dissociate or continue to produce longer time. Otherwise, we cannot assess the nature of the methyl hydrate occurrence. So it's too early to say that the sort of economics or those kinds of things. But of course, the Japanese government is pushing us that you have to raise the numbers as soon as possible but we still don't have enough information to do that. By the way, I forgot to share our ground rule with this audience. When you ask a question, please tell us who you are and who you're with and then wait for the microphone so that everyone can hear what you need to ask. Yeah, sure. Roger Cooper, Cleveland Park Policy Consulting and formerly American Gas Association. Thank you for both your work in this area. I've been a big fan of methane hydrates for many years and I think we're all sitting here going, OK, is this shale gas 15 years ago ready for a technological breakthrough? Based on just the six days of testing and obviously it's too early to talk about the climb rates but maybe as a follow-up also on the horizontal drilling, how do you, in an existing well, would you continue to go out horizontally with a deep pressurization technique? Is that the thinking of how you continue to produce in that area? Well, of course, maybe we may have to consider the extended production methods but at this moment we have to evaluate the deep pressurization method itself with the vertical well is the important things. So of course, we kind of had the experience that we drilled the horizontal well in the methane hydrant layers. We can do that. But even though that since this is sort of a deep pressurization method so that the way how we can kind of extend the area is kind of more important than the horizontal wells. So maybe cracking or these things maybe workable but we still in discussion on those sort of next stage. So but we believe that we may have to have some sort of sort of additional sort of a measure to dissociate the methane hydrant more. Just a quick follow-up. Does that mean that thermal stimulation is not off the table entirely? That may also be used with a deep pressurization method. I'm David Bardeen. I am retired. I served in the Department of Energy during President Carter's administration. I want to ask about the slide we have there. The green area, as I understand it, is a sandstone. And it's a porous sandstone. And then we have 270 meters above that. Do your core samples or other evidence indicate that there's any kind of ceiling layer above that sandstone? Or is it not going to? Well, that's my concern. OK. Good question. I explained that when we choose this sort of place as a testing site, we sort of identify the sort of like clay layers above this concentrated zone. So that can be worked at the ceiling for the deep pressurization. That's why we select that. Because going to Ms. Nakona's question, if you have a good seal there, it seems to me there'd be no difference in the risk of leakage between this and conventional natural gas. I mean, if you don't handle your well-righted, good leak, if you handle it right, you're going to get everything for your commercial production. Of course, if you have areas where the sandstone doesn't have a seal over it, that could be a different story. But we're taking it one experiment at a time. And I think it's pretty exciting what you've done so far. But as Lei said that since this is quite shallow formation, so that these layers are not consolidated enough. I mean, unconsolidated structure. So there may be change in these structures as well. Do you explain how the monitoring wells worked? What were you metering as far as gas flow? Actually, we put sort of a temperature gauge in these wells. To see if there was a temperature change. So just to detect the temperature here. So it shows a quite stable temperature. Over six days? No, no, no. But in six days, it kind of changed a lot. So we actually get quite interesting data through that. When a hydrate dissociates, it sucks up heat. And it makes the sediment substantially colder. That's how you actually find where hydrate was in cores. When you retrieve them in an expedition, you run an IR camera, look for cold spots. And how cold it is is a proxy for how much hydrate was there. So they were looking for evidence that hydrate around the monitoring wells had dissociated by the temperature change. And you didn't find any evidence of that? Oh, no, they didn't. But that was only six days worth? Yes. OK. Paul Connors Canadian Embassy, thank you. Go through your presentation. Ray, for you. I mean, we do this research, and we like to develop it due to eventual commercialization. So where we're at with natural gas. And after the shale revolution, I was wondering what the motivation is for the US government to keep researching this. One understands that importing countries with coastlines would be extremely interested in developing this technology. But if you accept countries like Canada and the US because of shale now have centuries worth and we have the climate change challenge, I'm just wondering, going forward, does the DOE appetite to keep researching this remain the same, or does it? I can't speak for the DOE appetite. My job is to implement the programs and give it as scientific a vetting as possible of something that looks like it's a future energy option. And I think everybody knows that the more options you have and the more well-fed it they are, the more well-served everybody is. Just to jump in a little bit, it's interesting that I've heard some folks, the North American energy sector, mentioned that they actually thought that a next breakthrough would have been not the shale, but methane hydrate, if we're talking about it, if we're, say, 10 years earlier. So in a way, sort of putting in a couple of different baskets. But I think your question is an excellent one. I mean, the US now has a very different energy profile. And so the whole range of, say, fossil energy-related R&D efforts that we could be undertaking, I'm always sort of curious as to where this may keep moving. Of course, that has lots to do with how it gets funded or continues to be, I suppose. But that's certainly, it's a lot more of a political or policy issues for this particular panel. But maybe one of these days, we can have folks from the policymaking world come here and then talk about some of these issues. Not a very question for the AI. No, no, but it was a great question. I mean, yeah. Robert Thomas, an independent journalist, natural resources, a new service. I'm interested in probing what you said about the production profile as best can. Is any indication that it would be similar to Shell or an unconventional in which a high percentage of production occurs in the first few years and then tapers off into a long tail? Or if you have any indication that it would be a different kind of production profile? It's a very interesting question. The first models of hydrate production suggested very long wait time, very low flat profile with peak productions out 20 years, large volumes, but long times. Once we got some data back from the field and began to create models that had a lot of fidelity to the actual variability that exists in the real world, they all changed. We started getting very short wait times in the models. They didn't have to wait any time for the gas to come up in their test. Potentially high rates early, and then production profiles that are short. And that's because the production is all a function of the surface area of your dissociation front. If you have a simple model, you've got just a cylindrical association front. And if you have a complex model, it becomes this highly corrugated thing. So the most recent models suggest its production profiles could be similar to what is seen in a lot of reservoirs, and not abnormally long and flat, as was originally thought. A much shorter earlier, sort of. Right, what was originally thought was scaringly long. This will never work. No one's going to wait 10 years for the first gas. That sort of thing. We don't think that's the case anymore. And all the tests have shown that it seems to respond immediately. Before production begins in your sandstone model, roughly how much of the pore space is water filled and how much is methane filled? When you said 50% of the pore space might be hydrate, I think that's what you said. What does that mean in terms of, in place, methane and water? And what's the rest of the pore space? The rest is water. Just plain water? Non-hydrate water? Yes. So of the hydrate, how much is water by mass or by whatever measure? I'm just to get my hand in my head around this. It's mainly water. It's not mainly methane, right? Yes, yes. What's the number, 83%? Do you know the number? Yes. Well, it's running from field by field, but like 70% saturation or something like that? We've seen up to 80% saturation. The rest of the water is, maybe half of it is free water, which is the water that can respond to a pressure. The other half of the water is bound to clays. Within the hydrate, the hydrate is, I should know this. This is why I'm embarrassed, but it's 80% water. So that's very high water compared to conventional natural gas production. I mean, I'd have to compare it with sort of geopressurized methane where the methane is dissolved in water to get into that kind of ratios. Tilly different question. What are the next two, I'll just say arbitrarily two production experiments around the world that you think all of us should be watching for additional, hopefully meaningful, interesting, fascinating results? Can you point to two? Well, as Kalmodasan mentioned, Alaska is a very good place to conduct the needed test, the longer duration test. We have been working with the operators up there who have the infrastructure to conduct such a test. And they have recently become less willing to enable scientific experiments to be conducted within their money making arena. So we've recently formed an agreement with the state of Alaska to sit in. And they have set aside 12 blocks adjacent to the production areas. 11, I guess. 11 blocks. Not 12. 12? 11. 11. Yeah, it's 11. For such time for us to work together to see whether they are suitable for a production test. And that's one of the things we're working on right now. This is in an area where there's no infrastructure. So there's no well. So there's a lot more geologic risk and uncertainty about exactly where you might put a test. So that is the thing we're working on now. And then, John, I believe Kalmodasan mentioned. The other one is, as I explained, that we are supposed to conduct an official production test in 2016 to 2018. We now started preparing for that. As far as you know, that's really going to happen. That's a commitment by the company in Japan to do it. At least you hope so. Well, this is sort of a plan of me. I'm in the Japanese government. And Jogmek is sort of that we are promoting this program on behalf of them. So probably we got to do that in the near future. So in four years or less, we might know a lot more. Yes, I hope so. Well, combining with the long-term official production test as well. So stay tuned. I think it's about time. So thank you. Ray Boswell and Takami Kawamoto, the leading experts on methane-hydrate science and technology, we're very honored that you could join us today. And please join me in thanking the two experts.