Carbon Capture and Sequestration in the U.S. with Shell

Speaker 1:
Welcome to Cowan Insights, a space that brings leading thinkers together to share insights and ideas shaping the world around us. Join us as we converse with the top minds who are influencing our global sectors.
Jason Gabelman:
This is Jason Gabelman, joined by Marc Bianchi from the Cowan Energy team. On this edition of the Cowan Energy Transition podcast series, we're pleased to be talking with Lee Stockwell. Lee is the General Manager of Shell's US Carbon Capture business. He's been at Shell for 20 years holding variety of roles in the upstream business, most recently as a General Manager of part of Shell's Gulf of Mexico business. He's been the General Manager of Shell's Carbon Capture business in the US for over a year. Shell more broadly has a target of 25 million tons carbon capture by 2035. It currently operates Quest CCS in Canada, and is participating in a number of projects, including Northern Lights, Porthos, Net Zero Teesside and Houston CCS hub. With that, Lee, it's great to have you.
Lee Stockwell:
Thanks, Jason. Appreciate the opportunity to be here.
Jason Gabelman:
Before we get into the carbon capture questions, it would be great to hear a little more about your background.
Lee Stockwell:
Yeah, thanks. As you mentioned, I've been with Shell for a couple of decades now and have spent the majority of that time in the upstream business and have done most anything under the sun in that side of the business; from development and exploration, research and development, the drilling and completion of wells, asset operations, the commercial side of buying and selling different assets, and as well as the safety and environmental space. I ended up in this job as a Carbon Capture and Sequestration General Manager for the US after several jobs had taken me through a lot of the connection to our emissions. So I was the General Manager for Safety Environment for our deep-water business and wrote the strategy for that business associated with greenhouse gas at the time. And then moved into that Asset Manager role in the Gulf of Mexico, where I was also the CO2 focal point for our entire operations in the Gulf of Mexico. So had an opportunity to really begin to get my fingers dirty, associated with what we're doing to take the step towards that net-zero ambition that Shell has. And through that said, "I really would like to own more of this. To be a tip of the spear, so to speak and have the opportunity to come and start to build our carbon capture sequestration business in the US, playing off the success in places like Quest in Canada."
Jason Gabelman:
That's great. Thanks. Can you give us an overview of Shell's current carbon capture footprint in the US and broadly how you see that footprint evolving in the coming years?
Lee Stockwell:
Sure, Jason. Maybe to start to say that in the US, we don't have any operations as yet for carbon capture and sequestration. So we are very much building a new presence for us. That said, we do have a lot of facility footprint here. Especially in the Gulf coast, we have multiple facilities in Louisiana and one remaining in Houston area. And for that, we want to ensure that we're decarbonizing that footprint. We also have a facility in Pennsylvania, our polyethylene facility in Pennsylvania, it sits maybe 20 miles north of Pittsburgh or so.
And our first intention of course, to decarbonize our own footprint. And so we will have CCS in those areas. Now we also wants to take the opportunity within those areas to help decarbonize our neighbors and communities. So what we look to do is build what we call hubs, decarbonization hubs, that take CO2 away from many different industrial players cutting across different sectors.
And so the big focus for us right now is the Gulf coast, it is that Pennsylvania tri-state area. And we're looking at other opportunities in the funnel, in different places where we're in conversations with folks in the ethanol business as ethanol is also a pure source of CO2 while also being a key feed stock for the future.
Those are the areas that we spend more of our time looking at right now. Certainly there'll be other that evolve, but places where we can both play in many value chains. So if we give you an example in Louisiana, we've just recently announced that, that we would be refurbishing our convent location into biofuels. CCS is a good way to connect into biofuels through blue hydrogen, which I'm sure we'll talk more about a bit later. But where we can integrate across multiple chains, not just for ourselves, but from of our fence line, neighbors or industry around us, we'll take the opportunity to do that as well. And those are things that you see in like the Houston CCS consortium that ourselves and 14 other players are there in the Houston region.
Jason Gabelman:
That's great. And you touched on a variety of topics that will hopefully address throughout the discussion. One of them is, you mentioned the importance of having an existing footprint to build your carbon capture business off of. Can you just expand on that point a bit? How important is having that existing footprint in order to build a carbon capture business from? And what type of advantages does that existing footprint offer Shell?
Lee Stockwell:
Well, I think for many players, you start with the volumes of CO2 that you need. And I think that in order to be successful in building a hub, you're going to need some sort of scale. And so building and aggregating the volumes that get you to scale is a key endeavor. When you have your own volumes to bring to that table, it most certainly makes that journey a bit easier. Of course, the type of assets that you have also impacts what it is that you're looking at.
So as you're very familiar in the US, we have a tax incentive called 45Q that provides $50 a ton for permanent sequestration, $35 a ton for enhanced oil recovery, CO2 abatement. And in that regard, you have to think through what volumes you have and the types of volumes. Right now, $50 a ton, from a cost perspective, you can really only manage the pure sources of CO2. And so you need some of those pure sources within your hub to be able to get you just from ground zero to a project that will work. And then over time as the incentives develop and you can add in harder to abate sectors. So not only do you need your own asset base, but you need some help with what exists from the type of CO2 sources that you're working with.
But being able to get that scale and having the infrastructure, for us we have long relationships in places like Louisiana and Pennsylvania. So to be able to work with the local and federal governments in those areas, those are also big helps in moving a project like CCS along.
Jason Gabelman:
Great. Just maybe one more on the existing footprint. You mentioned you have a variety of assets in the US and refineries and chemical plants, and these facilities have individual units. And I imagine CCS is only applicable to certain units. So can you maybe discuss what units are within the wider kind of refining and chemical plants that Shell has, where it makes sense to deploy CCS?
Lee Stockwell:
Well, I'm sure. I mean, you kind of have a whole gamut of what it looks like from, as you mentioned, very large say refineries or chemical plants, plastics, manufacturing locations. We have a footprint in the Gulf of Mexico with many different assets that sit out in the deeper water. We've got terminals all over the United States to move things around. Some of those things in terms of what we call point sources or places where emissions come from, are very difficult to capture because they're maybe very disparate, they're in different locations or they're small sources and it would cost too much to be able to capture all the different point sources. So typically when you're thinking about CCS, you about very large sources of emissions, hundreds of thousands to millions of tons per year. And then you would add technology to that to remove it.
So if you're in a position where let's say I've got an offshore platform, for instance, and I've got a bunch of very small places that put emissions through, and none of them are very large, in order for me to put an entire carbon capture facility in that place, it would cost a lot per ton of CO2. So my unit cost is very high and uneconomic. In places like a chemical plant where I've got both pure sources and large sources of CO2. I can put a capture unit in that location. And the cost per ton of CO2 would be significantly smaller. So across the assets we say, all right, what makes sense now, versus what may make sense later, and/or what technology needs to develop in order to capture smaller sources of CO2 over time? And those are technologies that are working as we speak.
Jason Gabelman:
Got it. What are the features in the US above ground and below ground, maybe from a policy standpoint that help and maybe hinder CCS deployment?
Lee Stockwell:
Right. I would say the first and foremost in the US is that you've got 45Q, which provides you a revenue stream. And that revenue stream is different than say what we see in the model in Europe, where you have, here, as of yet, there is no capital grants being given by the government that will change to some degree with the Infrastructure Act that was passed late last year. But to date, there has been none, and you have this revenue stream on the back end. In Europe, they provide the grant, but the return on that investment is capped like a utility. So you have very low margins that come off the back end of that. So here you have much better incentive to move a project forward where you can make money. You aren't constrained on what your outcomes might be. Only by whether you can make the economics work underneath the 45Q tax incentive. I think that is a big component.
The other is that in many of the states that are leading the way in this, you have very clear policy associated with CCS. So for instance, Louisiana, in 2009 passed a sequestration act, which very much details what happens with the CO2 or space. And you have the EPA Class VI injection laws, which dictate what it takes in order to inject CO2 onshore in the US. The Infrastructure Bill just gave the mandate to the Bureau of Ocean Energy Management to define the rules for offshore injection. So you have a very progressive policy frontier that continues to move things along and will open the doors for CCS to continue to evolve and move forward and see more and more states kind of stepping into that space and saying, "Let's create that clarity around it. This industry is one that connects to more and more places."
I think that's a great benefit for us. I think there are other sides like Canada, for instance, which has more of a carbon pricing associated with it. You see them moving because at a certain rate because there's a bit of a carrot and stick that's gets played on that front. The US doesn't have that yet, so it may happen at some point in time. And if it does, that'll accelerate this journey to some degree, but you do see varying policies in different places. I would say the US's policy is very mature relative to a lot of the planet, and one that is much more favorable than say the European side. So while Europe has looked at these mega projects and the barriers to entry are very high because of the regulations. In the US, there are all almost no barriers to entry in the onshore world for CCS. If you have the expertise and you have the funding, you can move forward.
Marc Bianchi:
Maybe, this is Marc, just to follow up on that, as you think about the expertise and maybe how the different functions exist for participants in the US market. So Air Products, for example, who we had on another podcast had acquired some [poor 00:12:45] space in Louisiana, and they're pursuing this project on their own. They're pursuing a blue hydrogen project on their own, but they don't have history doing subsurface stuff. I assume they're going to employ some oil field service company. But maybe talk about what Shell's expertise brings to the table in the US? Where are you going to be involved in actually owning assets versus where you're going to have third parties? I'm thinking about, perhaps you might not have a pipeline, somebody else is going to go to a pipeline. So like how far does your scope extend and how important of a competitive advantage is that?
Lee Stockwell:
I think one of Shell's benefits is the fact that it's a fully integrated company. So from the beginning to the end, we can choose which value chains we want to play in. So everything from the capture technology, which we have proprietary capture technology, all the way through to the underground storage and monitoring, which as a company, that's got a large upstream presence, is bread and butter. We can choose which one of those businesses we want to play in, depending on where we are on the globe, what the regime is, where our strengths are maybe specific to the region.
And I would tell you that, I look at Air Products and the announcement they made, which is great for Louisiana, good to see them moving in a space like that. But I agree with, there are a lot of companies that provide subsurface expertise and there are a lot of companies that can provide the drilling expertise if you need them. There are companies that can provide capture if you need them. So anybody who comes in can has the opportunity to say, "Well, we'll subcontract these different parts out and pull together a project." I think that the ones with the more of integrated view, will have a better chance of pulling together a project that maybe is a bit more advantaged from an economic perspective. But I would say that the expertise is available within the market.
I will say that we intend to be a part of all value chains, certainly in the Gulf coast and in the Pennsylvania tri-state area. We would like to be everything from the capture side, all the way through to the storage, that will be a place that we look to play. In addition, you'll see us in the blue hydrogen space as well, because they're kind of naturally linked between CCS and blue hydrogen. You'll see us exist in that value chain too. And I think that the expertise that we bring there from a proprietary technology in our partial oxidation, I think it will be an advantage as well.
So I do think that this suits us, we have experience in permanent sequestration that for all intents of purposes very few others have. That Quest project, if you think about the amount of tons per year that is sequestered currently around the planet, the vast majority that's for enhanced oil recovery, as opposed to permanent sequestration. So having that experience, understanding what it takes, I think gives us a bit of an advantage in that. Certainly when we have conversations with potential partners or governments, being able to sit down and say, "Look, this is a actually what it takes and let's talk about the risks and liabilities and the benefits of doing something like this. We can paint that picture and show that, what it takes to make it happen.
Marc Bianchi:
So we're not technical people, we're financial people. Maybe explain a little bit of the difference between enhanced oil recovery and sequestration. I didn't realize there was much of a technical difference, but it sounds like there is, maybe you could expand on that.
Lee Stockwell:
So maybe at the top side component of this, the what's on the surface, the capture components are roughly the same. Let's just leave it at that. Let's say we capture some CO2. And from that point forward, what you do with the CO2 is different between permanent sequestration and enhanced oil recovery. So in enhanced oil recovery, we would take that CO2, we would bring it to a place where there's existing oil production, and you would pump that CO2 into the ground for the purposes of moving oil and sweeping oil from say on side of a reservoir to another, towards the producing wells. And the intent there is to increase the amount of recovery from a normal formation where let's say, if I just pick numbers, that if you started with, you may have a 20% recovery and after injecting it with CO2, that 20% may turn into 30 or 40%.
And so there's value associated with injecting that CO2, what ends up happening there is as you inject CO2 over time, eventually that CO2 travels from where you've injected it to where it's produced and you start producing CO2. And then it becomes a bit of a treadmill where I continue to produce then capture CO2, then inject the CO2 again, over and over again. And because it's that, it's not permanent sequestration, but it is something that you inject CO2 for. And the reason that you continue to do that is for continued recovery. And eventually after the oil field has lost productive life, you would inject as much CO2 as you could hold and move that towards permanent sequestration, or at least that's the theory of how that would work. I'm not sure how many fields have been stopped and then used afterwards for CO2 injection.
Permanent sequestration would be saying, I'm going to look at this with a saline aquifer. So an aquifer that we don't pull drinking water from, and that would be much deeper than our drinking water levels. Then I would pump CO2 into that level without producing. And the difference between of course is, if I'm producing from an oil field, I'm relieving the pressure, and then I can put CO2 in, which would stabilize that pressure over time underground an aquifer, I'm going to increase the pressure, but I'm going to do it very slowly. And only to a certain point that it's contained within the rock itself. We would want to stay below the strength of the rock so we don't break or fracture the rock in any way, shape or form. So with that, there's a limited amount of CO2 that I can stick in a reservoir. And I have to monitor that very closely to ensure that I stay within those reservoir parameters. So the requirements for that permanent sequestration are somewhat more than the requirements for enhanced oil recovery. And for that, we want to make certain that we've got all the right things in place. Does that make sense?
Marc Bianchi:
Yeah, that's great. Maybe just real quick before I give back over Jason. So just in terms of service companies, only one of them has said that they have worked in Class VI before and have a demonstrated Class VI capability. How real of a barrier is that? Or, how hard is it for other companies to kind of get Class VI certification and be providing services for such activities?
Lee Stockwell:
Well, it should be recognized that to date, there's only been a couple of wells that have been approved for Class VI. So just for reference, the Underwater Injection Certifications UIC program, that the EPA manages has classifications that look at a lot of different things. If you were injecting water, for instance, it would be Class II. So CO2 is Class VI. And what's required for any well that may inject CO2 is a Class VI permit. And as I mentioned, there's only two that have been given out to date. Those were both in Illinois given to Archer Daniel Midland for their project. Those permits took I think four years in order to turn them over from beginning to end. So it's clearly a process that is new and hasn't been used very much. And you can see if there's only two that have been handed out to date, not many companies have a lot of experience with what it takes to gather those Class VI. So we're all kind of in that same boat in the US.
What's happening now is that many permits are being applied for. So you've got lots of applications that are now sitting in the queues in different states. Within the states, you either have the state that's asked for primacy over that Class VI permitting process from EPA or the regional EPA office. It will be managing that process itself. And what ends up happening in that is that you get all the data that you require from a well, you submit the permit that you want for your injection well. And then there's a bit of a process back and forth to understand what the application actually means, what are the implications of it and what are... They test the science of it. What are the environmental issues associated with the area with those wells? And they work through that process to understand that permit.
Hopefully in a time now shorter than four years, depending on where you're. Louisiana, for instance has asked for primacy, it has an expectation to get primacy sometime in Q2 of this year. They say their expectation is one to two years, in order to turn around a permit, it'll be different depending on where you are and who's managing that permit. But in that regard, all of us are going to be trying to gather that experience as we move forward, it won't be just the service companies.
Jason Gabelman:
Great. We could zoom back out to a maybe higher level. There seems to be different business models forming around CCS or CCS as a service, there's doing it within your own footprint. And maybe that is in part based on different infrastructure that companies have access to it. It would be helpful to maybe get a sense of the different business models, first CCS that are available to Shell and maybe to the broader market.
Lee Stockwell:
Sure. If we think about maybe at the highest level, the potential revenue streams associated with what CCS is, your first is around the government incentives, so your 45Qs or anything else that may exist in that space. That's kind of number one. The second is value from other value streams. So for instance, low carbon fuel standard in California, if I were to remove CO2 off of ethanol, and that ethanol was sent to California for use, then it would qualify for a low carbon fuel standard credit, which is a couple of hundred dollars a ton. That's another swath of value, things to that extent. And the last one's a bit of a markets. And so the ability to create cleaner products or lower carbon products through CCS, for instance, if we took CO2 off of steel and said, "All right, it's low carbon steel," the demand for that product and the premium that might be associated with that demand is another potential revenue stream. Those markets in terms of the low carbon products and the premiums, those are things that are fledgling as of right now.
There's not a big scope for what that is, but it is something that we do see more and more demand of. And within our own businesses for chemicals and products, more and more of our customers are coming to us and saying, "We would like low carbon feed stock for whatever our process might be." And there's some major companies that I think all of us would recognize on the store Shell's asking for that movement to occur. So while we see it's a bit fledgling now we do expect it to move forward.
I think the other part of that will be the societal demand. So my mental model of what things will look like in future is similar to the calorie counter and ingredients on the side of your cereal box. Each one of the products that you'll have in the future will have some sort of energy calorie counter, or how much energy has gone into this product, what is the carbon intensity of the shirt you bought, or the car you bought, or the TV you have. And it'll become something where people are going to start looking for lower amounts of energy used in order to make the products that get bought. And in that regard, you're going to look at things that are lower carbon in general, and CCS will be a facilitator for that. So you have those different views of what the revenue streams are.
In the 45Q space as I mentioned before, right now what is in the money are pure sources of CO2. And there are many of those that come from different industries, and that's where the business is centered right now, how do I make sure that I'm set up there? Your next swath will be either a reduction in cost of what it takes to get capture put in place or an increase in the incentive set that will unlock what we call harder to abate sectors or things that are kind of a higher dollar per carbon ton to abate. And that will be an addition as low carbon fuel standard expands and other standards get put in place, you'll see the expansion again from that perspective and more fall within that in the money funnel.
And then the premium side, or, or as we move to say what we consider something that probably needs to happen, where you have governments calling for lower carbon feed stocks into their capital projects, things like lower carbon steel or low carbon cement, those sorts of backed contracts will open up a whole nother swath. And you'll see kind of with each one of those, a stair step change in terms of how much CCS is being used and deployed based on the different expansions into business models.
Jason Gabelman:
Shell works with a lot of its customers to help them decarbonize. And you mentioned lower carbon products as an avenue, or as a business case for CCS, but how does Shell get comfortable that the demand is going to be there for that product, for the CCS? Are you speaking to customers and developing projects on a one off basis? Or are you saying, "We think the broader market is X, so we know the project is going to be supported? Or is it something else going on?
Lee Stockwell:
I think maybe a couple things come into mind when you say that. For us getting comfortable demand, as I mentioned before, it's always easy to get comfort when you have your own volumes. So when you've got your own emissions and you know you're going to be doing that work, it's, this is more around what the incremental might be for expanding into a position where you can help other people. I will say that the conversations that we have with different customers across a lot of different sectors are very similar in the sense that most people are trying to find their way and say, "What does an energy transition look like for us in this industry?" And that's something that Shell kind of end to end can say, "All right. Well, this is what we see." Or, "These are things that we can help with in different parts."
CCS may be one of many different solutions that get offered in that space, but many, I think it's a pretty well shared belief that the direction of travel is the same, at least to the folks that we're having the conversations with. And in that customers come to us their own volition and say, "We know we need to change." Or, "We know our supply chain needs to change. How can you help us? What does it look like? We want to do this by this period of time? What does that take?" Many of them come to us and say, "Well, how do we lean into a federal or a state regulatory environment with you? Or how do we show up in this position to say, "We recognize this needs to happen, here's what it takes to make that happen."
So I worry less about the demand, Jason right now, just given that if you look at the IEA reports or the BNEF reports, or pick your major accredited agency that looks through this, CCS is going to play somewhere between a 15 and 20% role in removing or attacking our net-zero ambition as a planet. If that's the case, we've got to grow by 150 times between where we are now and what that might actually look like over time. The question will be, how quickly can we get the regimes in place that will enable that to move and will bring the demand forward and time, then otherwise, you're going to take a small incremental approach to demand increase until you get to the position of having those markets start to develop.
Jason Gabelman:
We could touch on cost for a couple minutes. Maybe broadly, just frame the discussion, the split in CCS cost between the capture, the transport and the storage. And where do you see those costs moving over time? Where's the area within those three buckets where there is scope for the most cost reduction improvement?
Lee Stockwell:
Maybe to start with the last question first, we have been doing midstream pipeline, transport and underground development for a long time. This is something that we're very good at. We understand what it takes to go from point A to point B, as you start to increase the projects and the amount of work that gets done there, that learning curve will take place very quickly, but it'll be finite. The amount of improvement that you'll see on those spaces will only go down so much. And I don't want to throw a number out there, but relative to maybe the capture component, you'll only see so much movement on the transport and the subsurface elements of it.
But the capture's one where it's a bit of a big unknown, because the capture itself technology's been around for 40 years. Well, let me say that in a different way. Absorption of technology has been around for 40 years. There are four different types of technology, just for reference; absorption, which is a bit like getting water into a sponge. Adsorption, which is sticking to the surface of something, so it'd be like fly paper membranes, which would be your coffee filter. And then the last is cryogenic or freezing it. The most cost effective and the widely most deployed is absorption. But technology could change on all the other fronts and something could occur in that space where it becomes much more cost effective. And I know people are working on those technologies all the time. But that's kind of the big black box as to, as technology changes, which we're certain it will, we just doesn't necessarily know when and what scale. But as you get to those step changes, it most certainly would have the most opportunity come down.
There's a technology called direct air capture and typically for capture costs, the cost goes up as the concentration of CO2 goes down. They're inversely proportionate. Direct air capture looks to take it out the atmosphere where you're looking at very low, less than 1% type of concentrations of CO2 and it's cost are in the $500-$600 a ton range. So very expensive.
And then you move into what we call post combustion. So after a fuel is combusted, you take that emissions, they go up a stack, a flu stack for instance, if we were to capture that, you're looking at concentrations that are let's say sub 20% CO2. And that could be anywhere from $80-$120 at ton in terms of capture.
And then you move to say pure sources of CO2 say 90 plus percent. And if you're looking at pure sources it could be less than $30 a ton to capture. So each one of those changes depending what the purity is. The smaller end of that scale, the more pure sources, that cost to capture, there's not a lot of room for movement in that, but in the higher end of that scale, there's a significant amount of room. The view is the direct air capture over time will move from $500-$600 a ton to $100-$200 a ton. So you'll see significant swings for some of those technology pieces. Those are the ones that we're really interested in watching.
The cost relative, let's say you have $80-$120 a ton in your capture, your transport could be $3-$7 a ton, and then your subsurface could be another $5-$10 a ton, depending on how many wells you have to put where it is, those sorts of things. And those are kind of numbers that come out the Natural Petroleum Council study that was done, or the work that's been done by the global CCSI Institute. They show you the ranges for each one of those. And I think that's what we expect to see and move over time.
Jason Gabelman:
That's great. Maybe we could talk a bit about blue hydrogen for a couple minutes. Can you maybe just first discuss Shell's efforts in that area or particularly in the US?
Lee Stockwell:
Similar to CCS, it's a business we're building, and one that folks like Air Products have done a lot of work to place their flags and move forward. What we see in terms of hydrogen is a key enabler, that enables a lot of different opportunities to further decarbonize. So if you think about those potential solutions, you have CCS, which is one aspect, but you have the hydrogen business, which is another, and in the US, especially in the Gulf coast where gas is cheap, maybe not as cheap as it was a few months ago, but where natural gas is cheap, you're going to see blue hydrogen I think play a role there, prior to green hydrogen coming into the view. And I think Shell has, as I mentioned, our own technology that captures 99% of the CO2 associated with it. It is partial oxidation. So if you're familiar that the primary three blue hydrogen technologies are capturing CCS off of an SMR, a technology called ATR and technology called POX, partial oxidation. The latter two are or oxygen based systems. And so you end up in a very different environment than your SMR, both of which are cleaner, although both of which are more expensive as well.
Shell's technology is that partial oxidation technology. And because of the quality of that technology is something that we think many people will want. It's been deployed many places. What we would like to be able to do in the US is take advantage of the footprint that we have and the projects that we are developing to put some blue hydrogen in place. I think as of yet, we're still working on what scale that might want to be at, what regions we would want, but certainly the Gulf coast, certainly that area in the tri-state Pennsylvania area, I mentioned before, are areas that we're very interested in.
Marc Bianchi:
Are we talking about greenfield projects for blue hydrogen, or are you going to be retrofitting either adding capture equipment or taking out an SMR, replacing it with POX. And I'm curious on that latter point, how do you decide is it put capture on an SMR where maybe you're capturing 50% or you go replace the SMR and have a lower cost to capture, but maybe more upfront capital.
Lee Stockwell:
The answers will consider both, Marc, to answer the first question first, we'll look at both brownfield and greenfield opportunities. And then how you would determine between the two would, really what's required? So different levels of blue or different levels of low carbon product require different things, depending on which way the market goes. So if I have a product let's say biofuels, that needs to go to California, then it needs to be a certain standard of blue. And within that, you need to make certain that whatever the technique for capture is either on existing technology or for the POX, it needs to meet that hurdle. And so you'll start with whatever works for that particular value chain that you're looking at. And if it is that I need a higher cost or it makes more sense from a value point of view, to put a new partial oxidation unit, a greenfield unit out, or to capture CO2 off of an existing SMR, that you'll aim to look at which one of those suit your purpose
Marc Bianchi:
That's interesting about the decision for brownfield and greenfield and POX versus SMR. But one of the kind of challenges or maybe criticisms that we've heard for blue hydrogen in general, is that certainly when compared to green there's concerns that you're not capturing all of the fugitive methane that's in the whole supply chain. So upstream natural gas production, midstream delivery, gas processing, there's a bunch of fugitive methane that goes along with that. And when you throw all that in, what might seem like a 95% capture of CO2 on a GHD basis is much less attractive. What does Shell have to say about that? What do you do in your sort of upstream operations to ensure the molecule is kind of low GHD versus CO2?
Lee Stockwell:
Yeah. Some interesting points you touch on there. Maybe the first that comes to mind is it kind of depends on what you're comparing. If we're comparing standard production of hydrogen versus the production of blue hydrogen, then the supply chain for natural gas is the same in either case. And so the idea of being able to capture the CO2 off of the hydrogen production would result in a significant decrease in a net GHD basis. I do, and Shell does call for methane reform. We want stricter regulations in place for methane emissions. And we do a lot inside of Shell to ensure that our operations don't. So everything from making certain that the wells that we produce have the appropriate casing and don't have venting associated with those wells, to running all of our operations, all of the production side of it with LIDAR, which essentially helps to see whether there's potential any sort of potential gas leaks associated with methane. It is something that we spend a lot of time and effort ensuring that our process doesn't have leaks and that we remediate any that we find as small as they are whenever they come up.
Our motto inside of Shell is find small, fix small, so that we don't end up with something that's larger than that. So our belief is that you should very much take care of the methane within the supply chain so that, that is a stable process. And I do think that, that's something that our industry needs to continue to evolve and adopt standards as maybe as strict as ours in the total supply chain piece. But if I think about just the hydrogen perspective, the idea of saying that capturing CO2 on something that wasn't particularly captured, or wasn't specifically capturing CO2 before, could result in a net increase in emissions, from a math point view, doesn't make a lot of sense.
And I know that you'll probably spend some time talking about Quest with one of my colleagues, but if you think about where the Quest article came out, that there was some negative publicity that said that the Quest project emitted more than it captured, oh, that's just blatantly untrue. The Quest was never intended to be a hundred percent emissions. It was something that the DOE in fact, invested on a pilot project that we would say, "Let's try to capture 50% and show that the capture plus the storage would work." And it's actually done very well. It's captured roughly a million tons per year since it started. And that in a net is significantly less than it admitted beforehand.
Marc Bianchi:
Sure.
Great. Unfortunately, I think we're going to have to leave it there. I know we have a lot more questions, but that's all the time that we have. So Lee, on behalf of Marc and myself really appreciate you taking the time to talk about Shell's carbon capture business. Thanks a lot.
Lee Stockwell:
Yeah, thank you for having me. It's been a pleasure.
Marc Bianchi:
We really appreciate you, Lee. Thanks so much.
Speaker 1:
Thanks for joining us. Stay tuned for the next episode of Cowan Insights.

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