Eric Parker, Hydrogen and Fuel Cell Technologies Office: Hello, everyone, and welcome to our June H2IQ, part of our monthly educational webinar series that highlights research and development activities funded by the US Department of Energy's Hydrogen and Fuel Cell Technologies Office, or HFTO, within the Office of Energy Efficiency and Renewable Energy, or EERE. My name's Eric Parker and I'm the HFTO webinar lead.
This WebEx call is being recorded, and will be posted on the DOE's website and used internally. All attendees will be on mute throughout the webinar, so please submit your questions via the Q&A box you should see in the bottom right of your WebEx—not the chat box. Please use the Q&A box. And we'll cover those questions as best as possible during the Q&A portion at the end of today's presentations.
And so, with that, let's get right to it. I'd like to introduce our HFTO host for this webinar to get things started, Neha Rustagi. Thanks, Neha.
Neha Rustagi, Hydrogen and Fuel Cell Technologies Office: Thanks, Eric. I'm excited to kick off this webinar. So, our focus today is emissions analysis of hydrogen pathways. So, we're going to start with an overview of the GREET model, which has been funded by DOE for over 20 years to characterize life cycle emissions of hundreds of different fuel pathways, including hydrogen. And we're fortunate to have Dr. Amgad Elgowainy, who has been leading development of the model for 20 years. And then, after that we'll kick into a subsequent deep dive specifically on fossil pathways from the National Energy Technology Lab, where we're very fortunate to have Dr. Eric Lewis and Matt Jamison, who have been leading cost emissions analysis of those pathways, also for ten years.
So, with that, I'm going to kick it over to Amgad to get us started on GREET.
Amgad Elgowainy, Argonne National Laboratory: Thank you, Neha. And thank you, Eric. Hello, everyone. Today I will present on the GREET model with a focus on the hydrogen pathways and also with a focus on the greenhouse gas emissions.
So, I will start with where hydrogen is produced today and through what technology pathways. Here you will see large-scale hydrogen production throughout the United States. You will see where refineries are, which are the gray boxes, the ammonia plants, which are the blue boxes. These are the dominant pathways predominantly from steam methane forming of natural gas. There is some production from byproducts of the steam cracking plant, there is some production from the chloro-alkali plants. These are small, though. And then, there is some liquefaction units there, which will play into the life cycle analysis too to move hydrogen conveniently to some distributed locations.
So, when we look beyond refineries and ammonia today and are thinking of the hydrogen as an energy carrier that can decarbonize across sectors, here you see the Hydrogen at Scale initiative by DOE You see hydrogen pathways. From the left you will see the potential fossil sources with the CCS or CCU—carbon capture utilization and/or storage. You see the nuclear pathways; you see the renewable pathways. And producing the hydrogen, we'll find its destiny in some end use. Today I mentioned the oil refining, ammonia, but hydrogen is growing into the vehicle market—this is the fuel cell vehicles, hydrogen could synthesize drop-in fuel to replace petroleum field. Hydrogen can be used in metal refining, chemical production, along with displacing or replacing natural gas.
So, I will give you a feel for what we cover in GREET for the hydrogen production, which we call well-to-gate from the feedstock source, my source in HR—although a molecule and then packing it and moving it and then the end-use per unit of product.
So, for that we use the GREET model. GREET stands for greenhouse gases, regulated emissions, and energy use in technologies. GREET is available publicly at the link you see in the middle of the screen, with a significant user base globally. GREET covers the fuel cycle, which I will cover today, but also covers embodied emissions in materials that are involved in vehicles or in solar PVs or wind turbines, among others. So, embodied emissions in materials is another scope of GREET coverage.
So, here I would like to emphasize we have two platforms for GREET. We have the Excel platform, which is the legacy platform that we upgrade over time and update. I will give a demo there. We developed an interface for the hydrogen user in particular to be able to use that version of the model in a more user-friendly way. We have the .net platform also, which is user-friendly. And for both, we have YouTube tutorials. We have a GREET channel on YouTube that you could use and learn how to use the Excel or the .net version. GREET has other derivatives that you see on the bottom left of the screen here, and it has some high-level users, including the California GREET for the local fuel standards.
So, GREET focuses on environmental aspects, including energy. Energy use is important. We would like to know whether the energy is a fossil or not fossil—renewable, nuclear. The resource availability for the energy to produce a certain amount of hydrogen is important. Energy use also plays into energy security; it plays into the—the cost of energy plays into the equity aspect of energy and the cost burdens for end users. Air pollutants, as you see there, are important, and these will play a role when we cover the environmental justice and where air pollutants happen and the subsequent impact on air quality and the population. But today I will focus on greenhouse gases, as you see in the orange box there. And finally, GREET covers also water consumption. Water consumption will be important for hydrogen production, where are using electrolysis to split water into hydrogen or steam for steam methane reforming or other water use to grow either a feedstock or develop a feedstock or for the conversion process.
So, GREET has definitely hundreds of pathways. I highlighted there at the bottom—you see the hydrogen application there and the different feedstock sources. I will do a demo on this. We'll look at hydrogen as an intermediate for others—for example, drop-in fuels or chemicals like methanol or ammonia, and you have seen this in the Hydrogen at Scale bubble chart. So, I will cover some of these as I go throughout the presentation.
I should mention that the user is capable of creating his or her own pathway in GREET using the existing databases or technologies or resources for processes, among others. So, GREET is user-friendly in that sense that the user can develop their new pathways that are not already in place in GREET.
This is an example of GREET outputs. So, since November when the BIL was released, we put significant effort to cover and update every single pathway in GREET, those that are relevant really to the hydrogen communities. So, here will see the steam methane reforming at the far left. You see the byproduct hydrogen from cracker plants. And then you see the SMR with CCS, the coal with CCS, the biomass gasification, the chlor-alkali byproduct, and then the nuclear pathways, the renewable natural gas pathways, and the renewable solar wind pathways. And there you will see actually the results I put here, especially for the SMR, because the methane emissions, as you see there in the error bar and in the legend, could have significant impact on the carbon intensity for using hydrogen. And there you can see for the SMR today we could be between 9 or 11 depending on the methane upstream emissions. And for the SMR with CCS it could be three; it could be five. So, there are some key parameters, what I want to highlight here, that can impact the results. So, to go below that two kilogram of CO2 per kilogram of hydrogen mark, then you see starting with biomass you will be there. And it will be near virtually zero; you will look at the nuclear and the renewable pathways.
If we go beyond the making of molecules—so, what if we use hydrogen in vehicles? So, you will have really the impact of packaging the molecule, delivering it to fuel and compilation, the prequel in all of that will add to the carbon intensity. So, here I show well-to-wheels, and I pick a single application here. This is transit buses, fuel cells versus diesel. And again, it shows several pathways you see at the bottom of the screen, and I show a gaseous pathway versus a liquid pathway. The reason there is liquid is it is more attractive economically, but unless you source electricity such as low carbon to liquefy the hydrogen, it could add to the footprint of the hydrogen delivered and used in vehicles.
Here I show the California grade in particular because California is where most of the vehicles are deployed today. And you can see regardless of the pathways there is always some reduction. Even with the steam methane reforming of natural gas there is reduction because of the high efficiency of the fuel cell vehicles.
Here I show beyond—I mentioned earlier we look at embodied emissions—so, what is embodied emissions in hydrogen fuel cells, hydrogen tanks, versus other powertrains? You see here the electrified powertrains and the conventional powertrains. And then, we can pair these with the wheels you have seen in the previous slide to do what we call cradle-to-grave.
And it can go beyond really making the molecule to where we will use the hydrogen. So, here I show an example for the ammonia in particular, I mean, and you can see the different pathways there at the bottom of the screen. This is a baseline ammonia—I mean, 2.5, 2.6 tons of CO2 per ton of ammonia. If you capture the carbon from the reformer, then this will drop really by more than half. And if you want to go further, you could even capture from the conversion, of course, at a cost. And if you want to go new virtually zero, then you will need to source really a clean feedstock, energy feedstock like nuclear or renewables. Of course, this comes at a cost, so we look also at the TEA for that. You see the feedstock natural gas is relatively low cost. So, are the new capture form reformer, and/or from the combustion you see the cost of the ammonia per ton versus the cost of ammonia for the electrolysis pathways, which are strongly dependent on the cost of hydrogen compared to the cost of natural gas there.
So, yes, you can get deeper carbon reduction with a nuclear or renewable pathway, but it comes with a cost. And if we hit the 1-1-1 target, then we can be competitive there. Similarly, actually, I should mention here that the publications I have put really at the bottom of the slide for those who are interested. We do the same for the Fischer-Tropsch, actually the e-fuels, with hydrogen as an intermediate. Here we show again the nuclear pathways to make hydrogen paired with CO2 to synthesize different grades of hydrocarbon fuels that could be dropped into blend or replace gasoline, diesel, or _____. And again, we look at the costs associated with these carbon reductions and at what cost of hydrogen we can break even, and you put some range there of the historic prices for the mix of fuel combinations. And so, where we are competitive—again, if we are near the dollar, we can be competitive with the historic prices of gasoline, diesel, and _____. And again, the publication is at the bottom of the screen.
And the same for methanol. I will skip quickly for the sake of time. Synthetic natural gas. And also for steel production using direct reduction of iron. And again, you see the life cycle analysis using GREET here for the different decarbonization pathways, including the hydrogen and the _____ technology and what the break-even cost of hydrogen assuming no credits for the low carbon production of these different products.
So, I want now to jump into a demo. So, as I mentioned, we updated GREET—actually, the legacy pathways of hydrogen in GREET. Some of these we used to update annually and some of these needed an update. So, with that, we leveraged a lot of the work from our sister lab, the NETL lab, and Eric will speak actually about their fine work subsequent to this presentation. But I want to show you how—I mean, what kind of updates we have done. We put an interface to make the GREET Excel more user-friendly by giving the user the freedom to input their values for process input, outputs in their own units, and then also by sectors, emissions, and different scopes.
So, with that I will go to the demo. But before that I want to acknowledge the Hydrogen Office for supporting GREET for over two decades and acknowledge the ANL team who have been working on the hydrogen pathways over the past few years.
And these are actually the YouTube tutorial links if you want to know how to use GREET along with our models that are freely available for download and use along with these important publications.
So, with that I will spend five minutes to go over GREET. So, this is the new interface we put in GREET. This is a separate sheet in the GREET Excel. We call it "Hydrogen GHG." We put really some controls there to make things easier for the user to navigate through GREET. So, here we show what year is of value. This will be important in particular if we are looking at the grid mix impact, for example. We know the grid evolves over time, so if I pick a year—let us say a recent year. I look at central production. I can look at the steam methane reforming, for example. And then I can pick the feedstock for the steam methane reforming as conventional, yes. And you can pick any of the above, whether it is the technology, production technology, or the feedstock.
But next I will, say, input process data. And for that and to be consistent with the work by the National Energy Technologies Lab, I will populate exactly the process level data from their work to show you actually how you could really evaluate these. So, that report shows natural gas use and units of mass, which is pounds. So, I will do pounds. They show hydrogen in units of pounds. We can do pounds. Of course, some like scf, some like BTU, some like the kilogram or tons. Electricity, they have it in megawatts, so I will do that. And the steam, they have it in million BTUs. And then, I will just pull directly from their tables. So, it says we use 156,000 for 82 pounds of natural gas per hour to produce 44,369 pounds of hydrogen. And for that, we consume 13 megawatts—this is the power input to the plant. And then, we can produce the steam at 487.
So, adjust these in these units. And with that, we have a process level data and a customized unit convenient. And then, I will say "calculate." So, what the interface will do is it will format the data in the GREET native units. We'll give some information here, for example, about the process level efficiency. And then it will start to push through the GREET pathways and produce emission results as you see here on the right. So, here we show all emissions. Of course, of interest to us is the greenhouse gases. You see the scope one, scope two, scope three, the credit for the steam, the total, and then the total in kilograms of CO2 per kilogram of hydrogen. If you want to focus only on scope one, scope one is the facility level emissions.
So, I mean, here you can see really this is the scope one which was created, and the emissions from the facility will contribute 7.2, considering the credits. Scope two is electricity supply to the facility. And in this case for the SMR it is a small contribution. It is small compared to the contribution of the natural gas. And then, if you would like to look at the natural gas upstate contribution, we can see it is significant. So, out of the 9.3 or 9.4, the number we saw from the total, I mean, if I select "all" we will get really the total again and you will see the contribution for each is—I mean, 2.2-something here, very small for scope two, and the majority in scope one.
We could do the same for another important technology—let us say the electrolysis pathway, for example. And I could, say, also enter process data. Typically, we say kilowatt-hours per kilogram. I mean, for PEM it's typically 50 to 55. We could say my hydrogen is in units of kilogram, so we pick the kilogram and say for each kilogram I need a 50 kilowatt-hour. Of course, it matters what is your source of electricity. And here we provide a map of what you could use, the different mixes in different regions. The California mix is a different, even individual clean power supply. And I will pick the solar as an example here and then, again, calculate.
As you would expect, it will be basically zero because the solar PV itself does not emit GHG, the electrolyzer does not emit GHG. So, you would expect that you would see zeros for all three spots, which is not a surprise.
So, this will be a zero there. Of course, here we are not talking about embodied emissions in the solar PV or the _____, so this is just a way to get looking at the fuel cycle. If I push to the nuclear, for example, we will see that there will be some small footprint. And the nuclear could be actually more efficient if you use this, or to have a specific even pathway there for that one. Let us just pick the nuclear as an example, then you will see a very small footprint. I mean, you will see something less than 0.5 kilogram of CO2 per kilogram of hydrogen. And again, all of that will be in scope three.
So, here you see the 0.3. It is very small. Scope one, the nuclear power plant itself, it does not emit GHG. The electrolyzer does not. And the only small footprint is recovered of the uranium, the _____, the enrichment of the uranium, and the use to produce units of power and/or thermal energy to coproduce the hydrogen.
So, this is kind actually of the interface we have developed. And I know I am out of time, so I will turn it back to Eric and to Neha. I am sorry. And then we will take questions at the end of the session. Thank you.
Neha Rustagi: All right. Thank you, Amgad. So, several of the fossil pathways that Amgad was showing are based on an NGAP finding study done by NETL recently. And with that, I'm going to turn it over Eric Lewis and Matt Jamieson, who have both been doing cost emission analysis at NETL for ten years, and they're going to provide an overview of the report that they recently did covering natural gas, biomass, and coal pathways. All right, Eric, take it away.
Eric Lewis, National Energy Technology Laboratory: Great. Thanks, Neha, and thanks, Amgad, for that overview. It was nice interfacing with Amgad a little bit for this report and for GREET. So, as was mentioned, I'm going to provide an overview of the recent study publication that NETL put out focused on current commercial hydrogen, or fossil-to-hydrogen production pathways. This is an integrated TEA, or techno-economic analysis, and life cycle analysis. And you can see the link to access the report down below and a picture of the title page off to the side. So, I'd encourage anybody to just Google or go to that link to view the full study. Today I'll provide a summary of objective highlights and the approach to conducting this study, as well as a more detailed overview of what's actually in the study, as well as some results.
So, the justifications for DOE FECM, which is the Office of Fossil Energy and Carbon Management, to do this study is really to establish a basis of current commercial fossil-to-hydrogen production pathways, quantifying a levelized cost of hydrogen, as well as the greenhouse gas footprints of those pathways, and to use that the baseline reference for R&D program planning. The objective of the study were twofold—really, to put forth those reference cases focusing on coal, gasification, co-gasification of coal with alternative feedstock, and natural gas conversion technologies. The second objective was to identify areas of R&D to improve on the performance and cost as well as the LCA characteristics of those cases.
So, our approach for the study was standard in terms of carrying out a TEA and LCA. First, we set out to do a literature review to understand the current commercial, really focusing on the merchant hydrogen production landscape to assess whether or not hydrogen from alternative feedstocks such as biomass, MSW, waste plastics, are in current commercial operation. From that, we used those learnings to develop our design basis for the cases that were identified. Modeled all of these cases using Aspen Plus. There were a total of six cases. Leveraged our partnership with Black and Veatch at NETL to help develop the economic results of the study. And finally, we put out the report in mid-April of this year.
So, just to discuss some of the findings from the literature review, again, we focused on current merchant hydrogen production market. So, the slide or the graph to the right there really characterizes the high-purity hydrogen from natural gas global market. It segments by producing entity as well as the total capacity and buckets the total capacity of plants into size ranges. So, in general, these are mostly steam methane reforming plants. They range from 24 to 480 tons per day of hydrogen production. So, we did the same type of thing leveraging some NETL data, knowing that for the most part global high-purity hydrogen from coal is used for ammonia production in China from coal gasification. So, you can see the range of production plants from various types of gas fires in China. Used that data to inform our case capacities.
So, we also looked at whether or not hydrogen production from biomass and MSW were currently being produced commercially. We couldn't confirm or verify any such instances. There is a plant in Japan, a Showa Denko facility, that possibly produces hydrogen as a precursor to ammonia from plastic but that couldn't be verified. In terms of gasification technologies, the Buggenum IGCC and Eastman Kingsport facilities co-gasify coal with an alternative feedstock. The Buggenum facility has been decommissioned. The Eastman is still operating. But neither of these facilities produce high-purity hydrogen as an end product today.
Hydrogen and CO2 separation. There are a few instances of CO2 separation being done from hydrogen production facilities, SMRs—globally, Air Products in Port Arthur, Air Liquide in France. Both of these facilities operate at less than 90% CO2 capture, as they do not capture CO2 from the furnace exhaust gas. Cryogenics: CRYOCAP technology is used in the Air Liquide plants in France. There are multiple higher capture flow sheets or plant technologies that are being proposed based on ATR technologies in Europe and North America, and these use more conventional amine-based or solvent-based CO2 removal technologies. And PSA is the predominant hydrogen purification technology among those plants being proposed as well as those that are in operation.
So, our six cases are divided up into three natural gas reforming cases and three gasification cases. We looked at SMR with and without CO2 capture, AMR with CO2 capture, ATR with CO2 capture, coal gasification with and without CO2 capture. We also looked at a co-gasification case with a torrefied woody biomass with CO2 and that resulted in a net-zero or nominally net-zero production scheme.
In terms of capacity, we limited the SMR plants to a single stream limit of about 483 metric tons a day, or 200 million standard cubic foot a day. ATR being a more scalable single stream technology, that was bumped up in capacity a little bit to match our coal gasification cases. The net-zero plant is comparable capacity to the Buggenum facility that I mentioned earlier.
So, just to illustrate, our feedstocks are standardized as part of publicly available quality guidelines that NETL puts out—so, natural gas, coal, and biomass can be seen there. Our hydrogen production specifications—now, we didn't consider a specific end use of our hydrogen products in these cases. However, the standard being produced is suitable for downstream ammonia production based on the contaminants, contamination limits being shown there. The hydrogen purity at 99.9% exceeds ISO 14687 Grade A and Grade B end use specifications. Those are combustion applications and industrial power and heat applications. Worth noting that this hydrogen purity is not suitable for PEM fuel cell applications. In terms of pressure, the pressure produced in each of these cases is 925 psig, and that's suitable for bulk hydrogen transport pipeline injection.
So, we assumed that all of these facilities would require backed technologies. So, all of the regulated emissions are controlled through various gas cleanup steps shown in the report and here as well.
In terms of our feedstock costs, again, there are standardized for NETL studies. Currently, coal is $2.22 per MMBtu. Delivered natural gas is $4.42 per MMBTu. And the delivered biomass is $5.43. Worth noting, these are 30-year levelized prices, so these are not spot prices. And we assume that a grid price for power draw for each of these cases, threw out $71.7 per million—or, per megawatt hour based on some EIA data.
So, for performance modeling, like I mentioned before, we used Aspen Plus to generate material and energy balances, stream tables, gate-to-gate air emissions within the plants. Performance estimates and equipment lists were then used to cost each one of these cases. Now, the plant material and energy quantities were then used as inputs for our LCA modeling, which I'll present the results in a subsequent slide here.
Before I show some of the results of the study, it's worth noting some variability and uncertainty that's associated with these results. So, we didn't seek or set out to put together an optimization study. So, really, the plant performance, cost, and environmental footprints of these cases are reflective only of the configurations that were examined. There's numerous alternative flow sheets that could be considered that weren't considered as part of this study. Alternative CO2 capture approaches, alternative ways to basically get off the grid or generate power inside the plants, all of those variations would be expected to produce different results.
So, the capital costs carry an uncertainty range of -15 percent to +25 percent for our reforming cases, -25 percent to +50 percent for the gasification cases. Our life cycle results—and I'll discuss these in a little bit more detail in a subsequent slide, but the natural gas, coal, and basically all of our energy inputs carry uncertainty. The natural gas in particular carries variability based on the region of extraction, the source of the natural gas, as well as the coal varies depending on the reported coal mine methane emission quantities.
The LCA impact assessment method also impacts how the LCA results are presented. Now, the standard results that we'll show here are based on IPCC AR5 global warming potentials with feedback. Over a 100-year time horizon. And the global warming potential used as part of that for fossil-based methane is 36 kilograms CO2 equivalent per kilogram of methane. Now, I won't go over an assessment of using a different impact assessment, but the report does look at the impact of using different assessment methods on those LCA results.
So, efficiencies we quantify for each of the six cases in two ways. We quantify a coal gas efficiency and effective thermal efficiency. The effective thermal efficiency basically accounts for the power draw to run the facility equipment. So, you'll see for each of the cases, save for case six, our net-zero plant, electricity is imported into the plant so that that results in a lower effective thermal efficiency for each of these cases. In general, the reforming technologies have higher efficiencies on both of those metrics than the gasification cases do.
So, these are our LCA results. Let's see. The reforming cases, I'll first discuss SMR without CO2 capture. We actually report the LCA results in two ways, first without a CO2 credit for the produced expert scheme from that SMR plant without CO2 capture. And we also apply a credit in our case 1B there for that plant configuration. That's representative of most current US hydrogen production facilities today as they are produced.
So, going on to the reforming cases with CO2 capture, you'll note that there's a little bit of a—I'll call it a Whac-A-Mole effect where the applied CO2 capture really drives down the stack emissions, the gate-to-gate emissions, which are the blue bars, the blue segments of these bars, to less than 0.5 or so kilograms CO2 equivalent per kilogram of hydrogen produced. However, you do incur some emissions outside of the plant gates due to greater import of natural gas and the associated greenhouse gas footprint of that gas, as well as greater import of electricity and associated LCA emissions of that electricity in order to operate those CO2 capture processes within the plants.
So, the coal gasification cases, unexpectedly the without-capture case is the highest among the six. The applied CO2 capture to coal gasification, you actually just edge out the reforming cases. And of course, our targeted net-zero coal and biomass gasification case is nominally net zero.
And I'll back up. One other thing I wanted to mention is the uncertainty band applied to those bars. The higher uncertainty reflects the San Juan Basin extraction for natural gas in the United States, and that's based on conventional natural gas drilling. The lower band or the lower bound of the reforming cases is based on offshore drilling in Alaska, so there's a lower associated global warming potential of that drilling and transportation infrastructure.
So, capital costs. Unsurprisingly, the reforming cases are less capital-intensive than the coal gasification cases. The error bands represent the capital cost uncertainties that I—or accuracy that I mentioned earlier.
And moving on to the LCOH results, the reforming cases are lower across the board than the coal gasification cases, so that's the first takeaway from this graph. Now, without CO2 capture steam methane reforming unsurprisingly is the lowest among the reforming cases at about $1.00 per kilogram of hydrogen. Steam methane reforming with CO2 capture as well as autothermal reforming are about the same at about $1.60 per kilogram of hydrogen. ATR slightly edges out SMR. And coal gasification being very capital-intensive, those production costs are higher with our net-zero LCA case being the highest at $3.64. Now, none of these results carry any penalties for CO2 capture or tax credits, such as 45Q. They also don't credit the economics with byproduct sales such as export steam or any air gas such as argon.
Now, another thing to note is the natural gas contribution to the reforming cases is quite significant. So, with that, there really is quite a range of variability based on the natural gas price on a levelized basis around these figures for the reforming cases in particular.
And I will go over some of that sensitivity in the next couple of slides. This is the natural gas price sensitivity, and the vertical bar represents our baseline levelized natural gas price of $4.42 per million BTU, and you can see if that were to drop down to really a bounding case at $1.00, that's where you really start dropping down to $1.00 per kilogram of hydrogen produced for our capture cases—so, the reforming technologies.
Now, go up from the $4.42 to $8.00, $9,00, all the way up to $10.00. That's where we start to see some parity points with the reforming cases with coal gasification, albeit without CO2 capture on the gasification end.
Power price, there is less of a sensitivity to power price of these cases, although I'll note that the ATR with CCS does have an ASU—so, you see the orange bar is a slightly higher slope than the SMR case with CCS. And at about $70.00—or, I'm sorry, about $90.00 to $100.00 per megawatt hour, that's when you start to see some tradeoffs between the LCOH of the SMR and ATR cases with CCS.
So, one last sensitivity. There was a credit done in a side case—this is not reflected in our baseline LCOH results that I just went over, but a hydrogen pressure credit was applied to each of the six cases to normalize to a 300-psig pipeline pressure for hydrogen production. And this follows a similar methodology as is done for I believe it's the current centralized PEM electrolysis case study in the H2A models. That drops the LCOH by about $0.04 per kilogram of hydrogen.
So, in terms of future work that identified FECM that will hopefully be pursuing, renewable natural gas lending with reforming cases in order to understand the LCA implications as well as the cost implications of doing that for the reforming cases. Low carbon auxiliary powering of the reforming cases in particular through integration of fossil-based power with CCS or renewables or even combusting the slipstream of your hydrogen product to get low carbon power, understanding the LCA and cost tradeoffs of that. There's also advanced reforming concepts that really look at process intensification of the reforming chemistry as well as some of the process steps in order to drive down capital costs and improve process efficiencies. And of course, excluded from this study was NG pyrolysis, so there's a need to understand the merits and demerits of different natural gas pyrolysis technologies.
So, just to leave off with some final thoughts in terms of study utilization. Amgad went over how these results have been incorporated in the most recent GREET updates. Ongoing is updating some of the fossil-based H2A production models. And FECM exercises a version of NEMS, so there's currently a buildout of a hydrogen market module within that version of NEMS. And also, this study has proven to be valuable for some pathway screening analysis in order to support the Hydrogen Shot DOE initiative.
So, I'd be remiss in not acknowledging all of those who worked on this report, including our peer reviewers. Standard disclaimer here. If there any questions about the study, feel free to reach out to any of the contacts below. And I believe that's all I had. So, I think we have some time for questions.
Neha Rustagi: Great. Thank you, Eric. So, anyone who has questions, please keep typing them into the Q&A box and we'll get to as many as we can. So, I'll start with—I'm on GREET, so Amgad, this one is for you. What is the default assumption for CCS rates within GREET?
Amgad Elgowainy: The default assumptions for CCS are based on the work by NETL that Eric has presented. So, whether it is for the natural gas, SMR, whether it is for coal gasification. So, these are all based on the NETL process level data.
Neha Rustagi: Great. And Eric, what was the CCS rate that was in your core case for SMR?
Eric Lewis: Yeah, for SME it's about 95%, 96%.
Neha Rustagi: Great. Thank you. This is, I guess, for both of you. So, are you planning on doing similar emissions or cost analysis for ATR, partial oxidation, methane pyrolysis? Maybe, Eric, if you can speak to, I guess, the role of NETL in these technologies and for these more advanced fossil pathways?
Eric Lewis: Yeah. So, of course POX is not included in this study, and that was really driven from the standpoint of to our knowledge there have been no announced projects based on POX technologies. However, POX with CO2 capture is commercially being offered by Shell. We haven't done analysis around that. We've had discussions with Shell, so there is hope to do some of those studies. There's some tradeoffs that are interesting for the POX technology, mainly around inside-the-plant hydrogen generation and how that can serve to maybe get down that greenhouse gas footprint.
Like I mentioned before, natural gas pyrolysis, that's definitely an area that FECM is going to be looking at putting some analyses together to understand cost and environmental footprint tradeoffs around.
Neha Rustagi: Great. Amgad, does the GREET interface allow the user to toggle whether or not you export steam?
Amgad Elgowainy: Yes. Yeah, I mean, you have seen I put there some value. You could put zero. So, if you put zero, there would be really no credits for steam.
Neha Rustagi: All right. And then, in the future is there a plan to incorporate global warming potential of hydrogen as a metric within GREET?
Amgad Elgowainy: Yes. This is the plan. And we have discussed doing the hydrogen _____, about having that into a future release version of GREET. Not for this one. This one would be released in a few weeks. We are just doing some quality control. But the model along with a publication that will document all the updates will be out in a few weeks, but in a subsequent version we will include GWP for hydrogen.
Neha Rustagi: Okay. So, generally speaking, Eric, how, I guess, realistic is the 95% CCS rate from an SMR plan? Is that what you would expect or is that ambitious, what they're able to predict as being viable?
Eric Lewis: Yeah, like I mentioned before, that hasn't been demonstrated commercially. But that's mostly due to high levels of CO2 capture haven't been planned for any of the operating facilities. Now, I'll say it's ambitious in the sense that in order to get to that high level of CO2 capture we did—had a second water gas shift reactor to push that CO2 conversion or CO conversion to push that beyond 95%. But a lot of it comes down to applying for SMR. CO2 capture technology—so both the flue gas, which has not been demonstrated at large scale, but the technology is being commercially offered, as well as the syngas in order to get to those high levels of CO2 capturing in essentially two steps.
For ATR the advantage there is doing everything pre-combustion from your syngas. So, high levels of CO2 capture, again, have not been demonstrated for that technology but the commercial offerings are—that's what's being proposed today.
Neha Rustagi: All right. Can you also speak to how well each of the emissions from natural gas production are characterized? There appear to be a wide range of values used across models today.
Eric Lewis: Yeah. And fortunately, on the call there's two representatives from NETL's LCA team, so I might hand it over to either Matt Jameison or Tim Skone, who both worked on this report, and they'll be able to shed some light on that.
Matt Jameison, National Energy Technology Laboratory: Sure. So, again, as mentioned in the presentation, we try to cover kind of the full gamut of emissions for the US, at least as NETL has managed them—Alaska offshore production and San Juan conventional as kind of the two far ends according to the NETL analyses. Yeah, I think to recognize the wide range of values used in today's modeling, the NETL model uses mostly publicly reported data in GHGRP to characterize those emissions. So, we're confident that we have a pretty good characterization of the emissions factors as reported publicly, recognizing that there's other literature out there, that from—different data sources might suggest even wider variation in those, but those aren't covered in this.
Neha Rustagi: Okay. So, the basis right now is the EPA GHGRP?
Matt Jameison: Largely, yes.
Neha Rustagi: Amgad, a question for you. When will the version of GREET that you were showing the demo of be available?
Amgad Elgowainy: Yeah, the plan is in two or four weeks, depending on how quickly we go through the quality control, if we find issues or not. It should be within four weeks.
Neha Rustagi: And then, also a question for you: What would be—I guess this is more a higher-level question—what are scenarios where renewable natural gas could be viable for reforming rather than just used directly in RNG form? And I guess this is, I think, for Amgad.
Amgad Elgowainy: Yeah, so we have several pathways for RNG in GREET. So, we have the landfill gas. We have the NSW. We have the animal waste. We have the wastewater treatment plants. So, all of these are pathways that can produce RNG with different carbon intensity. And then, the reformation of the methane will be similar to what we used from the NETL report.
Neha Rustagi: And I guess maybe scenarios for fuel cells, for example, can facilitate higher efficiency where there's already a market for hydrogen. Maybe those are the ones where RNG reforming is more likely to be—is likely to have a play, rather than direct use.
Amgad Elgowainy: It depends, right? It depends. So, for example, if you reform RNG to make hydrogen and you use it in a high-efficient powertrain like fuel cell vehicles, you could get something significant created there. So, it depends on the end use. I mean, if you are using BUT—for a BTU, yes. If you have some efficiency gain and your end use is like a fuel cell powertrain, then hydrogen could be very attractive, even from RNG.
Neha Rustagi: Okay. And that is done in California today, correct?
Amgad Elgowainy: Yes.
Neha Rustagi: Eric, this is a question for you. Were the environmental impacts of amine included within your CCS analysis?
Eric Lewis: Sorry, could you say that one again?
Neha Rustagi: The environmental impacts of amine emissions. I think they meant, like, the amines.
Eric Lewis: Yeah, no. The short answer is no. However, Shell CANSOLV was modeled for our SMR case. There is a gas cooling step and knockout steps to reduce that. I am aware that Shell recently changed their solvent to minimize solvent carryover into the exhaust gas. But that's not something we explicitly quantify in our environmental analysis.
Neha Rustagi: Okay. And then, are there any plans, I guess, for—in both of your work, generally speaking, to include black carbon or soot in your GHG emission calculations? We can start with—I'm going to sort of start within GREET and then…
Amgad Elgowainy: Yes, we have black carbon, organic carbon as GHG contributors in GREET. So, these can be toggled on and off, but they do exist in GREET.
Neha Rustagi: And then, Eric, do you want to...?
Eric Lewis: Yeah, so that mostly applies to our coal gasification cases, and that's quantified in our study and it's based on the target emission limit of those particulates.
Neha Rustagi: Amgad, for the cases on one of your slides where there was a range bar for SMR CCS—I think it was coal with CCS—can you speak to the parameters that are kind of covered by that range, variables that would vary to get a number within that bar?
Amgad Elgowainy: Yes. So, that error bar was in particular to highlight that there are certain upstream factors or parameters upstream of the SMR that could be influential, and those are results, and there we learned at a lower limit—this is, I believe, the latest EPA of 0.7 leakage rate, and the natural gas supply chain, and the upper end was 3.0. And like Eric mentioned, it could be different by the region and by the place or—I mean, we just show what does it mean, because this could be—have a significant impact on the carbon intensity of the hydrogen produced.
Neha Rustagi: Within GREET can a user change the GWP for methane value, like from 36 –?
Amgad Elgowainy: Yes. Yes, yes. We have the—all the historic values from the IPCC and the most recent GREET follows the IPCC, the AR6 report.
Neha Rustagi: All right. There were a few questions about ATR, so I think, Eric, this is for you. What are the circumstances, what are the kind of general scenarios where deployment of ATR relative to SMR could be advantageous, variables that could make it advantageous?
Eric Lewis: Yeah, so starting with the reactor itself, it's fundamentally different from SMR. So, external heating of your natural gas feed isn't required with ATR, so you essentially combust a portion of your feed stream. So, that plays out in reactor design. SMR has large—a large reactor footprint. ATR doesn't require as large of a footprint and capital cost, so there's an advantage there for ATR. In terms of CO2 capture, I mentioned before all of the CO2 is concentrated essentially in the syngas stream. You don't have a low-pressure flue gas stream to deal with, so that advantages ATR in terms of CO2 capture and capture equipment efficiency, et cetera.
Now, the disadvantage for ATR is of course the ASU for hydrogen applications is required to meet that high purity hydrogen end product. So, that's basically the tradeoff between the two.
Neha Rustagi: All right. Good deal. So, we are closing in toward the end of the hour and so I want to be respectful of everybody's time. So, I really want to thank Amgad, Eric, Matt Jameison, and the entire team for putting this on. We really appreciate your sharing. This is representing one year of direct work but many decades of work that led to this point. And so, we look forward to making GREET available. And the NETL report that Eric's been speaking to, we dropped a link to it in the chat. If you have additional questions, please don't hesitate to reach out to us or directly to the speakers. And with that, I will turn it back to Eric Parker to close us out.
Eric Parker: Thanks, Neha. And thanks to our presenters and everyone else who made this possible. That does conclude today's H2IQ hour. I mentioned it earlier in the Q&A but we will be posting the full recording of this webinar and the slides on the HFTO webinar archive in around a week's time, so be on the lookout for that. And use the time in the meantime to sign up for our newsletter to be notified about additional webinars and other exciting stuff from our office. So, with that, have a great rest of your week, everyone, and goodbye.
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