Below is the text version of the webinar titled "An Overview of the Hydrogen Fueling Infrastructure Research and Station Technology (H2FIRST) Project," originally presented on November 18, 2014. In addition to this text version of the audio, you can access the presentation slides.
Alli Aman:
Thanks for joining today's webinar. I'm going to go through a few housekeeping items before I turn it over to today's presenters. Today's webinar is being recorded, so a recording along with slides will be posted to our website in roughly ten business days. I will be sending out an email once those are posted to our website, but I definitely encourage you to check back to our website for those.
[Slide 2]
Everyone is on mute, so you will see here on the screen, we encourage you to ask questions during the presentation, so when you have a question, please submit it via the question box here, and then we will cover all questions at the Q&A at the end of the presentation—or get to as many as we can.
I definitely encourage you to check back to our website for future webinars, as we do host these monthly, and sometimes we have two a month. I also encourage you to sign up for our newsletter, which we send out monthly, so you can also do that on our website.
And on that note, I'm going to turn it over to Erika Sutherland. She is a technology development manager for the Fuel Cell Technologies Office, responsible for hydrogen delivery activities. Erika?
[Slide 3]
Erika Sutherland:
Thank you, Alli, and I'd like to welcome everybody today who's listening in. We're happy to give a webinar on the Hydrogen Fueling Infrastructure Research and Station Technology, or H2FIRST, project, and I'm going to be introducing our two project leads who will be talking about this project today.
First I'd like to introduce Dr. Joe Pratt. He's a principal member of the technical staff at the Department of Energy's Sandia National Laboratories, located in Livermore, California. He conducts research, development, demonstration, and deployment activities on hydrogen and fuel cells. He's focused on both overcoming the technical and non-technical challenges associated with hydrogen fueling stations and the transition of hydrogen and fuel cell technology to a commercially viable product in applications such as aircraft, construction equipment, generators, portable devices, and onboard maritime vessels.
Prior to Sandia, Dr. Pratt was an assistant professor at the University of Michigan at a joint institute in Shanghai, China, where his research focused—focusing on applications of alternative energy. He completed his MS and PhD degrees at the University of California Irvine in mechanical and aerospace engineering, where he studied the effects of high altitude on fundamental fuel cell behavior through first-in-the-world experiments.
Prior to graduate school, Dr. Pratt developed practical systems expertise at Parsons Energy and Chemicals, designing and building combined cycle natural gas turbine power plants. He received his BS in mechanical engineering from the University of Washington.
Also speaking today is Mr. Chris Ainscough. He is a senior engineer at the National Renewable Energy Laboratory, and he has worked in the hydrogen and fuel cell industry for over a decade. Chris is very committed to delivering on the promise of clean energy. Prior to NREL, he was a chief engineer at Nuvera Fuel Cells, located just outside of Boston. He earned his master's degree from the University of Pennsylvania, specializing in micro-electromechanical systems, and is also a licensed professional degree.
His bachelor's degree is from the Colorado School of Mines in Golden, Colorado. Chris has received numerous awards for his outstanding technical contributions, awards from industry, from the Fuel Cell Technologies Office, and he's also received NREL's President's Award. Chris is currently pursuing a law degree focusing on energy and natural resource law at the University of Denver. I will now turn it over to Chris to give the introduction.
Chris Ainscough:
Thank you, Erika, and thank you, Alli, and for everyone else who's attending.
So we want to talk today about H2FIRST, which as Erika mentioned is the Hydrogen Fueling Infrastructure Research and Station Technology Project, so you can see why we call it H2FIRST.
[Slide 4]
So the objective of H2FIRST is very plain and simple. It's to ensure that fuel cell electric vehicle customers have a positive fueling experience, end of story. And really, if customers don't have a positive fueling experience, that may be the end of the story.
It's absolutely critical that the consumer experience with fuel cell electric vehicles be just as good or better than the experience with gasoline vehicles. So this project is a project of the Fuel Cell Technologies Office within the Department of Energy. It is co-led by the Natural Renewable Energy Lab, which is where I'm at, and Sandia National Laboratories, which is where my colleague Joe is at.
The idea is to leverage unique core capabilities at the different labs and make the sum of the two parts stronger than the individuals. This project supports the goals and objectives of H2USA, and we'll get into what H2USA is in just a little bit, if you're not familiar with it.
Right now, H2FIRST has three tasks that are ongoing. The first one is called the Hydrogen Station Equipment Performance Device, or HyStEP. The idea behind this device is to give station operators and stakeholders in the industry the ability to validate that dispensers are actually meeting the fueling protocols that are available in industry, both from SAE and CSA.
The second task is a hydrogen contaminant detector, and this task is to look at and develop an inline sensor that can give you an early warning of quality problems with the hydrogen. This is not meant to be a replacement for the SAE J2719 standard that specifies what hydrogen quality should be, or testing that's required under that standard, just an early warning.
The last task that we currently have in the queue is the reference station design, and you'll hear my colleague Joe Pratt talk about that in a little bit.
[Slide 5]
So on to H2USA. H2USA is a public-private collaboration between industry and government whose objective is to commercialize fuel cell electric vehicles by overcoming the hurdles with hydrogen infrastructure. We realize that many of the challenges—whenever you talk to somebody about fuel cell electric vehicles, often the response is, "Wow, these are really cool. Where do I fill it up?" And H2USA aims to address that question.
[Slide 6]
So the specific goals of H2USA are to establish hydrogen infrastructure by leveraging multiple energy sources, and these include natural gas and renewables. This is one of the neat things with hydrogen, is that there are many different pathways that you can use to make hydrogen. The most common in industry today is a process called steam methane reformation that uses natural gas, but it's also possible to make hydrogen renewably from electrolysis and other technologies. And electrolysis, if you don't know, is the splitting of water molecules into hydrogen and oxygen.
H2USA also has a goal of deploying FCEVs, and that's the acronym for fuel cell electric vehicles, across America; improving America's energy security and economic security, reducing greenhouse gas emissions; and developing domestic sources of clean energy and jobs in the United States; as well as strengthening the domestic supply base for the clean energy sector.
[Slide 7]
H2USA has a number of signatories to the letter of understanding, and I want to thank—I know many of you are on line now—I want to thank you for your contributions and your continued efforts here. I think this is very important work, and I'm excited and very fortunate to be a part of it and have the chance to work with all of you.
[Slide 8]
So now a little bit more into H2FIRST. Our long term objectives are to reduce the cost of fueling stations, to make them more competitive with liquid fuel stations. So there are a number—as of present count, there are 52 hydrogen fueling stations in the country, many of which are controlled access, some of which are public, but that's changing. There are new stations coming up, particularly in California. But we want to make the cost of those stations lower in order to enable there to be more of them.
We want to improve the reliability, the availability of them, because these stations use high pressure components. You'll see a lot of numbers thrown around in this presentation regarding 70 MPa or 700 bar. If you don't speak bar and the metric system, that's about 13,000 psi—or that's about 10,000 psi, and you have pressures up to 13,000 psi in some cases. So we want to increase reliability.
We also want to make the experts at the labs available to help solve these challenges. We have a lot of both capabilities in terms of human capital and test facilities that we can bring to bear on these issues. So we want to make sure that we're making the best use of those.
And further, we want to enable distributed generation of renewable hydrogen in the broader context of the energy systems of the 21st century, which our President has delineated as an all of the above strategy. We want to look at all of the energy technologies we have available, because it's going to take all of those to make sure our economy is robust and we have sufficient energy to drive everything.
So this graphic shows what H2FIRST—the scope of H2FIRST really is tackling. So you have over here on the left side the storage tanks, so hydrogen will be either delivered as liquid or gas, or generated on-site through perhaps an on-site steam methane reformer or an electrolyzer. And then what H2FIRST is working on is the storage tanks, the compression, and the chiller, which we'll get to in a minute, and the dispenser and the interface with the vehicles.
[Slide 9]
So as I mentioned, H2FIRST is coordinated with H2USA, and this graphic shows how the H2USA Hydrogen Fueling Stations Working Group is set up. So within that working group, there is a thing called the H2FIRST Coordination Panel that we just kicked off last week at the Fuel Cell Seminar. The idea behind the Coordination Panel is to provide industry perspective on R&D and generate ideas for what R&D needs to be done, review progress and results of the team, and to identify potential partners and perhaps even participate as project partners in the different tasks that we identify that need to be done within H2FIRST.
So in that way, we want to make sure that the work that H2FIRST is doing is—has input from industry and is relevant. We want to make sure that we're working on the hard challenges and the hard issues that are facing the hydrogen infrastructure industry today. And all of this is done under the backdrop of ultimate decision authority with the Fuel Cell Technologies Office at DOE, so that would be Erika, who you heard introduce us.
[Slide 10]
So with that in mind, I'm going to go into some more detailed overview of the tasks we have going on within H2FIRST now. The first task is, as I mentioned, HyStEP, which is the Hydrogen Station Equipment Performance Device.
[Slide 11]
The goal behind this device is to accelerate commercial acceptance of stations by making a device which can validate a station's performance relative to the standards, the fueling standards, that are in industry today.
The team consists of vehicle OEMs, station providers, and state government agencies, and the lab teams at Sandia and NREL. The two protocols that are relevant for hydrogen fueling right now are SAE J2601 and CSA HGV 4.3. So right now, there isn't a good way to drive up to a station, maybe a newly commissioned station and say, yes, this station meets all the requirements of the fueling method. And this is important, because nothing's quite as simple as pouring gasoline into a metal can, which is what we do today, in a sense. I know it's more complicated than that, but there are some other things we need to consider when we're fueling hydrogen into vehicles.
[Slide 12]
So some of those, why we need HyStEP, is because as hydrogen is compressed into a vehicle tank, it heats up, and this is an unavoidable fact of physics. You compress a gas, it gets hotter. So to mitigate that, what we do is hydrogen is typically precooled as low as minus 40 degrees C, and the fill rate is controlled to control the amount of heating that happens. And the heating is important because the vehicle tanks are nearly all made of carbon fiber composites, and those have thermal limits that must not be exceeded for the durability of the tank.
So these two protocols, 2601 and HGV 4.3, specify how exactly to fill vehicles safely. And we all—everybody, all the stakeholders in this space, have a vested interest, manufacturers, consumers, station operators, we all want to know that our vehicles are being filled reliably, safely, and that we're getting what we need from them.
[Slide 13]
So toward that end, the specifications for HyStEP are—this is a broad overview of them—the device is meant to be mobile, so it needs to be mounted in a truck bed or a trailer so it can be moved around to the different stations in the country. It will initially have Type IV 70 MPa tanks with a 4 to 7 kilogram capacity. Now again, if you're unfamiliar with what 70 MPa is, that's 70 megapascals, which is equivalent approximately to 10,000 psi. And 4 to 7 kilograms… so a happy accident of nature is that one—the energy equivalence in one kilogram of hydrogen is almost exactly the same as that in one gallon of gasoline. So you can think of this device as having a 4 to 7 gallon gas tank, if you like, if that makes it easier.
And this range is chosen because those are the ranges that are in current fuel cell vehicles today needed to get about a 300 mile range in the vehicle, because fuel cell vehicles are much more efficient than gasoline vehicles, so you don't need as much energy on board.
HyStEP is designed, again, to initially meet or test a subset of the HGV 4.3 tests, but we may add others in the future. For instance, Honda is developing a method called the MC fill that uses a different approach to filling, and may have some advantages.
The device will include an SAE infrared communication right now when you do a 70 MPa fill. The station and the vehicle communicate back and forth, or the vehicle really communicates to the station, and so HyStEP will have that capability.
The device will have temperature and pressure sensors in multiple locations to monitor the pressure ramp rate, ambient tank, and gas emissions—and here you can see, just a broad overview of where the sensors will be and what the ranges on them will be.
And one other important feature that HyStEP will have is it will have the ability to simulate leaks, because you want to be able to shut off the hydrogen in case of a leak on the vehicle, or a leak on the dispenser hose. So it will be able to test that and make sure that the dispenser responds appropriately.
[Slide 14]
So where we're at in this project, this is an overview of the timeline. The RFQ was issued in September. We spent October reviewing proposals, and right now are in the process of negotiating a contract to build the device. Following that, we have a pretty aggressive timeline to develop the design, review the safety analysis, build it, do the initial testing, and then it will be sent here to NREL to do some validation testing before being sent out to its first field assignment, which will be an Air Liquide station in California.
[Slide 15]
So the next task I want to go to is the hydrogen contaminant detector.
[Slide 16]
Again, as I mentioned, the objective of this task is not to replace required sampling under SAE J2719, but rather to provide an early warning that there may be a quality issue at a station. The last thing we want to do is put impure fuel into a vehicle. We don't want to use the vehicle as a guinea pig. So this is important.
Sort of the two sub-tasks within this are first off, a market survey, and this is—the idea behind this is look at the whole range, the whole universe of detector technologies that are out there, that are capable of detecting the contaminants that we care about. And then the second one is to look at it from the other end and say, well, what are the requirements of a detector in terms of cost, its detection levels, pressure, all the engineering requirements that you usually think of?
[Slide 17]
So some of the desired characteristics and challenges with this are as follows. You really want the detector to be easily integrated into a station, and some of the challenges here, you have multiple station configurations, which we'll see in a minute, and you have extreme gas temperature and pressure. So—low temperature, high pressure, which can create some challenges.
The contaminants detected, the list of contaminants in J2719 is quite exhaustive. However, we recognize that depending on how a station is built and where its hydrogen source is, not all contaminants are probable at all stations. For instance, you're unlikely to have CO contamination at an electrolyzer station. The chemistry doesn't support that.
Levels of detection. The levels of detection required—excuse me—in J2719 are difficult to achieve with current technology. Many of them are very low ppm, some are even ppb levels.
Cost. So much of the existing technology that's out there for detecting these contaminants is expensive and is generally laboratory grade, and isn't hardened for an essentially gas station environment. The maintenance on these items is typically frequent and specialized, and requires a special knowledge set to run it. So we want something that's inexpensive and doesn't need specialized knowledge to run. It will just be a sensor that—like a pressure or temperature sensor, can go online and measure the hydrogen as it's coming through.
The key point of all of this is that near term solutions will be tailored to individual station technologies based on the probable contaminants, using a risk-based approach.
[Slide 18]
So you can see some possible configurations of what you would have at a hydrogen station here. You may have delivered hydrogen, and this could either be delivered gas or liquid, and there are different implications for either of those. A reformer, and again a reformer is a device that takes methane and water and turns it into hydrogen and carbon dioxide. And some of the contaminants you could have in a reformer are carbon monoxide, water, sulfur species—this comes from the mercaptans that are in the natural gas—hydrocarbons, residual oxygen, and particulates.
Electrolyzers, again what an electrolyzer does is it uses electricity to split water into hydrogen and oxygen, and you can have residual water contamination there, oxygen crossover possibly, and maybe particulates. In addition, there are outside sources. So what you see there is the tailpipe of a bus. It's our favorite vision of what particulate matter looks like.
So when you think about where you want to put contamination detectors, you can put them in a number of locations. So you can put them right where the hydrogen comes into the station, which is one way to do it, and has certain advantages. You can put it toward the tail end of the station, so that you're picking up any possible contamination that the station itself is putting into the gas stream. And you could also put it on the car, which has some issues.
[Slide 19]
So some of the pros of these, if you look at location 1, the pressure requirements are actually pretty low, because you usually don't have the full pressure of the 875 bar fill at location 1, and reformers are usually—electrolyzers also are usually pretty low pressure devices, in the hundreds of psi.
A good reason to put it into location 2 is because that, as I mentioned, captures all contaminants. So if anything's getting in there from the compressor, the chiller, the storage, you're going to catch that. And then location 3, which is actually on the vehicle, you're going to catch everything. So even environmental contaminants, something that—particulate matter that comes from maybe a dirty fuel receptacle or things like that—it'll catch all that.
Some of the cons of these, so as I mentioned, location 1 misses contaminants that come from the station itself. Location 2, you have to deal with the high pressure gas, high pressure and low temperature gas. And location three, really, we see that as a burden on the vehicle OEMs, because—both in terms of packaging, weight, and cost, and just the simple fact that there will be many more cars than stations, so if you can make fewer contaminant detectors to catch all of the hydrogen, that's probably a better thing for the market.
[Slide 20]
So looking at—this is somewhat of an older study that was done by NREL and some data from Shell Hydrogen, that looked at the—on the x axis, looked at the difficulty to attain the level, attain and verify the level of different contaminants. And you see some of the typical bad actors we talk about in fuel cells—ammonia, hydrocarbons, carbon dioxide, sulfur species, carbon monoxide. And some of these are actual poisons and can damage the fuel cell. Some of them are just diluents and are just a problem because they're not hydrogen. So those would be like nitrogen or helium.
So you see the difficulty to track them and attain the level of them, and then the impact on the fuel cell. So you can see some of these things above the line here are typically stuff that we want to avoid putting in a fuel cell. Among these, carbon monoxide is usually the most common, and is one of the ones that we want to focus on a lot.
[Slide 21]
And here's a very recent result from my colleague Sam Sprik at NREL, who is tracking the number of samples from J2719 sampling at stations since 2009. And so you can see the number of samples going up and down. Wherever you see one of these flags here, this shows you that a contaminant was detected outside the limits of J2719, and what that level was in terms of micromoles per mole, which you see down here at the bottom. And it's worth noting that typically when you see a lot of samples like this consecutively for the same constituent, it's because somebody was having an issue and trying to figure out what that issue was and fix it, so it's not that all stations were having issues with water in their fuel. It's just that they were—perhaps the one or two stations were having an issue and trying to resolve it.
[Slide 22]
So the market survey of contaminant detectors is looking at relevant technologies, prioritization of detectors for the most impactful contaminants. Again, we want to use a risk-based approach and look at what contaminants are likely from which sources. And then we also want to marry that up with which commercial technologies are suitable for deployment out at a station. Then we want to look at the engineering gaps between what we have and what we need. So NREL and Sandia are also working with Savannah River National Lab, another one of our sister national labs who has some expertise in this area, developing work plan and timeline. The initial output will be the market survey and engineering requirements.
[Slide 23]
Some of the technologies we're working on, we're looking at right now, really fall into four broad categories. And I'm not going to read these all to you, but as Alli mentioned, the slides will be available. But you have gas chromatograph technologies, mass spec, piezoelectric, and optical technologies. So—and these all have different pluses and minuses and costs associated with them, so this is actually a pretty broad solution space that we're looking at.
OK. So that wraps up the hydrogen contaminant detector. Now I'm going to turn it over to my colleague Joe Pratt at Sandia National Lab to talk about the reference station design task. Joe?
[Slide 24]
Joe Pratt:
Thanks, Chris. Yeah, you can go ahead and do the next slide.
[Slide 25]
Great. So the objective of the reference station design task is to develop station designs based on state of the art components and characterize the cost, throughput, reliability, and footprint, with the help of DOE models. In a couple of slides I'll get into the approach in a little more detail. I just wanted to touch on the reasons why we're doing this.
We're hoping that the final station designs could be used by those interested in developing, owning, or operating near term hydrogen stations. For example, they could refer to the conclusions in our work, such as the type of stations that would be low capital costs, or low hydrogen costs, or best use of capital, and decide to build a station aligned with these results, as opposed to station concepts that we show may be relatively worse investments.
In addition, because this is an independent assessment of station economics, they may be able to use this information to assist in obtaining more favorable financing terms by lowering the risk of the economic unknown.
As a result of this work, we anticipate lower-cost hydrogen stations because of this decreased economic risk associated with financing, building, and operating a station. There is potential for more competitors in the marketplace, and there are lower up front conceptual design costs, because we can help station developers quickly determine the suitability for a particular station design based on available site and vice versa. Next slide.
[Slide 26]
Some of the station characteristics that we're looking at—and this is just an example layout from a different project, just to kind of show what we're talking about here—some of the characteristics we're looking at are the type of hydrogen delivery, and I want to point out that while this first iteration of this task focuses on delivered hydrogen, future iterations will look at on-site generation, as you mentioned before, the steam methane reforming and electrolysis. We'll be looking at daily capacity, so in other words, how many kilograms of hydrogen could this station dispense in one day? How big is the land area needed to install this station, either at an existing gasoline station or on its own site, with the cost of the hydrogen that results from all the equipment that you need to build a station, the capital investment, the configuration of different compressor methods, the size of the hydrogen storage, the capacity for consecutive fills, so if multiple cars are lined up, how many cars in a row can the station fill before it sort of has to recharge? And then also the number of hoses, which some people refer to as dispensers, so that's another characteristic there. The next slide. Thanks.
[Slide 27]
This is—I want to point out it's a highly collaborative project. We're trying to leverage all the resources within DOE and the Hydrogen Fueling Station Working Group at H2USA. You can see our project or our task is in the lower left corner here, and we're leveraging analysis tools that Argonne National Lab has developed for long term station design guidance. We are modifying those to look at now term, so short term station designs.
We're taking all the input, both from DOE and various other projects that they have, and also using H2USA Hydrogen Fueling Station Working Group as our voice of the industry and private sector to help inform what we're doing. At the same time, the outputs from our project will hopefully go right back to industry through the Hydrogen Fueling Station Working Group and help DOE with their other efforts as well. Next slide.
[Slide 28]
So I just want to talk a little bit about the approach. What we started out with in step one was defining the parameters and the ranges of those parameters that were going to be studied, and so this goes back to a couple of slides where I mentioned all of the different things we're looking at.
We also wanted to make sure that the values of these, for example, the station capacities, are what is anticipated for near term stations—not necessarily long term, ten years from now—to try to make these results as useful as possible right now.
We specified in step two the cost data and the metrics. What this alludes to is the Argonne work before was focused on long term and mass production costs, and we needed to instead look at what would it take to buy these pieces of equipment off the shelf right now to install in a station, so incorporating that information into the task is what step two was about.
In parallel with steps one and two, Argonne worked on a modification of their HDSAM model, which they're calling HRSAM, which only looks at the hydrogen station itself, and incorporates these near term or now term costs that I was mentioning. So using the results from step one and step two, and this modified model from Argonne, we were able to specify and simulate different station concepts for the economics of cost per kilogram of hydrogen and also the capital costs of building the station.
Using this information, then, we can select different stations based on these comparative economics, as well as looking at some of the other non-economic parameters, like land size and applicability to near term rollout scenarios that are being looked at across the country. That is currently where we are with the project.
The next step will be to optimize the selected stations, mainly integrating the actual components that we can buy today. After that is a review process with DOE and industry via H2USA, and then we'll get into producing the station designs for these selected stations. These station designs will include spatial layouts with codified setback distances, building materials for the equipment that we've specified and associated costs, and the process flow diagrams. And that's all I have, Chris.
Chris Ainscough:
OK. Thank you, Joe. So that is what the—that's really the high level overview of where we're at with H2FIRST. This is a relatively new project, and I'm excited to be working on it.
[Slide 29]
I did want to give some information to everybody. In case you want to be—become involved in H2USA, you can email info@H2USA.org or visit the H2USA website to get information on how to become involved.
[Slide 30]
To specifically get more involved in H2FIRST, here are the contacts at both Sandia National Labs and NREL who you can get in touch with, and I'll leave that up for just a moment.
[Slide 31]
But I did want to also give contact information for myself and Joe, and give you a shortened version of the link to the H2FIRST website. We did just launch this last week, so it hasn't really made it up into the Google page ranks yet, but it is there with a number of FAQs and overview of what the—what the task is doing, and what we're all about.
So with that, if anybody has any questions, as Alli mentioned, type them into your question box, and Erika will be trying to prioritize those questions for us to answer. So Erika, what have you got for us?
Erika Sutherland:
Well, the first one was easy. It was asking when the H2FIRST and H2USA website was launched, and I think you just addressed that one, as they are both currently available.
Chris Ainscough:
Done. All right.
Erika Sutherland:
Yes. Next question I'll send your way is—this looks like a basic question. The audience member would like to understand, since the fuel cell produces water, why is it considered a contaminant when it is in the hydrogen?
Chris Ainscough:
OK, so that's actually a really good question. The way a fuel cell makes water, and the question is absolutely correct, fuel cells do make water. That is the primary constituent of their exhaust, is warm air and hot water. The difference is that the hydrogen goes into—so a fuel cell is an electrochemical cell somewhat like a battery, so it has an anode and a cathode, a plus and a minus, if you will.
The anode, which is where the hydrogen is fed, has to be very, very pure hydrogen, like 99.999—a lot of 9s—purity. And so any time you get water or any other kind of diluent in there, like helium or nitrogen, things that aren't hydrogen, what that can do is cause carbon corrosion on the anode support. So what you have in the anode is you have usually some sort of carbon that is a support for the platinum-based catalysts, and those diluents can cause—if the fuel cell needs to put out power and it can't get hydrogen to the reaction sites, it will basically eat the carbon, and that's bad.
So the water that a fuel cell generates is on the other side, on the cathode, and so water's fine there, to some extent. You don't want too much water. But—so that's the short answer.
Erika Sutherland:
Great. And there was a follow-up to that question asking right now, how is water removed from the hydrogen stream?
Chris Ainscough:
It depends on the technology. Often, onsite reformers will use a pressure swing absorber, which does a number of things. So a reformer will basically make hydrogen that's pretty pure. There's the steam methane reformer, then there's what's called a high temperature shift, and sometimes a low temperature shift reactor, that injects more steam and reacts with carbon monoxide to make more hydrogen and then CO2.
So the pressure swing absorber will—it's a bed of particles that the gas flows through, and hydrogen being one of the lightest gases there is will come through first, and sort of the—some of the heavier things, like hydrocarbons, methane, carbon monoxide, carbon dioxide, those will stay behind. So you run it such that the hydrogen comes through first, and then you'll switch beds. You'll either have two beds that are switched back and forth with valves, or some companies have a rotary design where they have different beds that sort of—they actually spin and go to a fresh bed, and then the bed is regenerated, and then the process repeats. So that's typically how it's done.
Erika Sutherland:
Thank you. Another question related, on slide 21—
Chris Ainscough:
OK. Let me go back there.
Erika Sutherland:
It's asking is the data broken down by the production source, such as a reformer or electrolysis or delivered?
Chris Ainscough:
We do know the data, based on the production source. However, so this project is—this result comes from the FCTO's technology validation work, which is headed by Jason Marcinkoski, who's also one of the sponsors of H2FIRST. But one of the key tenets with technology validation is we gathered data from stations all over the country, and vehicles all over the country, and then we published the results in such a way that one company's proprietary data, their—isn't publicly available.
So we gathered a bunch of data, but we only publish data so that we protect everybody's anonymity, and that's—we've been doing that type of work at NREL for about—over ten years now. So although we do have that data, we can't publish it, because we want to make sure we keep everybody's identity safe.
Erika Sutherland:
Thank you. Next question for you, can you talk about the benefits of the different types of stations, specifically delivered gas or liquid hydrogen versus reformation, steam methane reforming, or electrolysis?
Chris Ainscough:
I think I'm going to pass that to Joe, if you don't mind, Joe.
Joe Pratt:
Yeah, sure, Chris. There's pros and cons for each, for delivered hydrogen and for onsite generation. In some cases there's—I would say a general feeling that the delivered hydrogen potentially results in cheaper installation costs for hydrogen fueling stations, because the equipment associated with onsite production, whether it's electrolyzer or steam methane reformer, can add a significant capital cost to the stations.
Overall, in the long run, and when you start getting into larger and more mature stations, on-site generation could definitely provide you the lowest cost of hydrogen, but there is this tradeoff with capital. If you have a mature market where your stations are utilized to a high capacity, then this tradeoff could be acceptable. What we're anticipating is that in the early days, station utilization could be as low as 20 percent, which makes it difficult to justify the increased up front capital cost of on-site generation. So that's from a numbers point of view some of the tradeoffs with onsite generation and delivered hydrogen.
Chris Ainscough:
Thank you, Joe.
Erika Sutherland:
OK. Next question for you gentlemen, related, what is the cost of a hydrogen station today compared to that of a gasoline station?
Chris Ainscough:
So Joe, do you want to take that one, too?
Joe Pratt:
Sure. What I've read is that gasoline stations are on the order of $200,000, maybe a little more, maybe a little less. Hydrogen fueling stations can vary widely in their costs, as I just alluded to, depending on how you build it. We're finding some of the cheapest stations can be built, that would be a very low capacity and delivered hydrogen, maybe around $1 million or a little less, with current equipment off the shelf today. Larger stations can get upwards close to $2 million, if you were to really build it out for a mature and highly utilized market.
Chris Ainscough:
Right. And that's, like Joe said, around $2 million. This is where the California Energy Commission is looking at about what a station will cost in the near term, so that—they're the sources of that, to support that from the CEC.
Erika Sutherland:
Just to note a comparison between the two, the gasoline market is an established market with high volume discounts.
Chris Ainscough:
Absolutely. Right.
Erika Sutherland:
[inaudible] there, which we don't currently have in the hydrogen markets. We do expect those costs to fall just based on the economies of scale, in addition to the R&D that we are supporting.
Chris Ainscough:
Absolutely, Erika. As I mentioned earlier in the presentation here, we currently have 52 hydrogen stations in the U.S. There are similar numbers in other countries, such as Germany and Japan. But I don't even know how many gasoline stations we have. Tens of thousands. So there are huge economies of scale to be gained when we start to get larger rollout. And in the U.S., that rollout is primarily happening in California with some funding from the state.
Erika Sutherland:
Thank you. Next question is would there be an advantage to co-locating hydrogen production with CNG/LNG stations to reduce overall costs? I think this might actually mean hydrogen delivery with CNG/LNG stations.
Chris Ainscough:
There can be some synergies there. A lot of the technologies are very similar. Typically, the compression levels for CNG and LNG tend to be lower. I believe CNG stations are around 3,600 psi. So—but you have a lot of the same issues. And as—one benefit you could realize, again, with—as I showed—here, let me flip back to the slides a little bit. If you have an onsite reformer—let's see, where is this at? Yeah, so if you have an onsite reformer here [Slide 18], there are companies that package these in sizes small enough to be located at a retail station.
And if you have a ready source of some sort of hydrocarbon fuel, it doesn't have to be natural gas, although that is the best in terms of the hydrogen density in the source fuel, then you could have a readily available way to make hydrogen on site, and you don't need to—then if you think about you're delivering fuel gases to the site, you could deliver the fuel gas with a natural gas pipeline, and then have compression for your natural gas vehicles, and then you could take a slip stream of that, run it through a reformer, turn it into hydrogen, and then you have hydrogen on site, you manufacture it on site as well, which is actually a pretty cool concept. You don't really think about manufacturing gasoline on site, but that's in essence what you can do.
Erika Sutherland:
Thank you. The next question is asking how would a hydrogen reactor perform in an Arctic type climate. So I'm not sure, I think they may have been asking how would a hydrogen fuel cell perform in the Arctic climate.
Chris Ainscough:
Oh, so fuel cells, the—well, I'll answer both questions. So the fuel cell vehicles, something the auto OEMs have worked very aggressively on is dealing with the issue of freezing water. As we all know, as water freezes, it expands, and usually in the tiny small crevices of a fuel cell, that's not great.
But I will say that every auto OEM whose vehicle I've driven has managed that issue, and the vehicles can be frozen down to very low temperatures and still run. They've met expectations and targets for the amount of startup time from those cold conditions. Usually I believe it's a minus 40 degree soak. Both—so they met startup time requirements and startup energy requirements, because you don't want to use all of your fuel just for warming up the vehicle. So those are good to go.
For a hydrogen reactor, if you're thinking of the—a reformer, that's going to be like any other piece of process equipment that you're going to have in an Arctic condition. It's going to need to have the inside cabin maintained at a relatively decent temperature. Reformers themselves, the reactor runs at about 800 degrees C, so usually they make enough of their own heat that it's not an issue, as long as they're running.
Erika Sutherland:
Thank you. The next question we have is with the H2FIRST project, is the work applicable to only light-duty vehicle stations, or will it include medium- and heavy-duty stations as well?
Chris Ainscough:
Hmm. You know, I think—I don't know if we've directly addressed this in our FAQs, but that's a good question. We're really looking at—there are opportunities to work with the sort of commercial vehicle stations as well. So if you think of one of the more successful early rollouts of fuel cell technology, it's been in material handling equipment, what we normally call forklifts, right?
And there are a lot of similarities between those stations and a light-duty vehicle station. A forklift station will typically run at about half the pressure of a vehicle station, but many, many of the components and the challenges are the same. So the work that we're doing on 700 bar light-duty stations will benefit the commercial vehicle, industrial vehicle stations as well.
Joe Pratt:
And Chris, I just want to add that as part of the reference station design task, we have been talking about looking at commercial or heavy-duty fueling stations at some point in the future, just not in the current iteration.
Chris Ainscough:
Right. Yeah. I think it's fair to say that our focus now is on light duty, but we're not taking—turning a blind eye to the industrial sector.
Erika Sutherland:
In the designs for the reference station, we are considering the inclusion of 350 bar fueling alongside the 700 bar fueling in order to address those markets.
Chris Ainscough:
Right. And—yeah, and that's an important point, because it's not just the forklift fleets that use 350 bar. Buses also typically will use 350 bar.
Erika Sutherland:
All right. I'm going to give you two questions that came in around this. When will the reference station design parameters or report, when will this information be released? So what is the timeline for that project?
Chris Ainscough:
So I'm going to give you that one, Joe.
Joe Pratt:
Yeah. Sure. We're hoping to have some results by the end of this calendar year.
Erika Sutherland:
Thank you. Another question—well, two questions on the same topic. What are the other sources of hydrogen that are being considered, aside from steam methane reforming and water electrolysis? What are the other production methods?
Chris Ainscough:
So actually, the FCTO has a well-developed production portfolio that are looking at sort of longer term technologies. So some of those include what's called solar thermochemical hydrogen production, or STCH, and actually, Sandia is one of the leaders in this area. They—so what a STCH process does is it uses high temperature heat, usually from a solar—a concentrating solar power source, to partially oxidize a metal oxide framework in the presence of water. And that essentially has the effect of splitting the water, much like electrolysis does. However, STCH has the promise of being able to be run at very, very large scales, using solar thermal power.
There's also a project at NREL that's looking at fermentative production of hydrogen. So this is the idea of just like you would ferment a batch of beer, you would have specially designed organisms that would ferment a batch of hydrogen for you, again, something you could do on the large scale.
There are also a number of other chemical processes. Savannah River I believe is working on a hybrid sulfur process that uses a number of chemical steps to split water. There was some work done at Argonne National Lab on a copper chloride cycle that can, again, split water. These are all different chemical processes that essentially are ways to split water.
So there are a number of things in the pipeline, and there's nothing right now that's as cheap as—natural gas is the cheapest performing, and so every petrochemical plant practically in the world will have an SMR on site, and that's because the hydrogen is used to upgrade petroleum. So you use it to upgrade lower—heavier hydrocarbons into lighter, maybe more valuable hydrocarbons like gasoline.
So natural gas is the cheapest right now, and then you have electrolysis is commercially available. So those are your big ones.
Erika Sutherland:
All right. Two more questions related to steam methane reforming. One is how is the CO/CO2 that's produced during the steam methane reforming process handled?
Chris Ainscough:
So—and I alluded to this a little bit earlier. So the steam methane reformer is actually a number of chemical processes sort of married together. The first one, which happens at around 800 C or so, depending on your hydrocarbon feedstock, takes methane and steam, so that's CH4 and H2O, and it makes some hydrogen and some carbon monoxide, typically is what you'll get, which is also called syngas, right? So synthesis gas.
You then take that to a water gas shift reactor, which usually will—may happen in two different stages, both a high temperature and low temperature shift. At that point, you put in more steam, and over a different catalyst react the CO with the steam to make CO2 and more hydrogen. So when you get done with those processes, what you usually have coming out is a very hydrogen-rich stream with some CO2 in it.
Now typically in small onsite reformers, you're just going to vent the CO2, or what happens is all this gas comes into the pressure swing absorber. The stuff that's hydrogen goes through. The stuff that's not goes back into the burner, because it has some residual fuel value. There may be some methane slip as well. There may be a little bit of CO left, and CO will burn.
So you'll take all that what's called raffinate back to the burner to provide more heat for your process, and then eventually it all goes out as a—as just flue gas. However, for large centralized SMRs, there is the ability to sequester the carbon. In fact, there's been a very successful project down in Port Arthur, Texas, between Air Products and the Department of Energy, so that SMR unit has sequestered something like—I know I'm going to get the number wrong, but you can look it up—it's over a million tons of CO2, and used it for enhanced oil recovery. So what they do there is they separate out the CO2 and then pump it back into wells to produce more oil. So you can sequester it, and that's been very successful.
Erika Sutherland:
Thank you. We have about five minutes left, and lots more questions. I'm going to ask a few more, but then the ones we don't get to, we will follow up by email. The next question I'll ask now is a question about onboard methane reforming. Has that been considered, instead of storing hydrogen onboard? What about storing methane and having an onboard reformer?
Chris Ainscough:
So actually, that's a good question. My very, very first job working in the fuel cell industry was working on an onboard gasoline reformer. So the challenge with those, and there's even more of a challenge with onboard methane reforming, because onboard methane reforming, you still have to store a high pressure gas, so that doesn't benefit you in any way relative to hydrogen.
So—plus, you have to have all the additional apparatus of the reformer, and the challenge with reformers is they tend to operate at sort of slower time scales, not the type of time scale that you experience when you are at a red light and you mash the gas pedal. So that's a challenge.
So there was a lot of work maybe ten years ago on onboard reforming, but most of that has stopped now, because we realized that for reliability and cost reasons, this is—the approach we're going on now is better.
Erika Sutherland:
Thank you. So we have another question here on are there any contaminant resistant fuel cell designs or research in that area?
Chris Ainscough:
That's a very active area of research. As I mentioned, CO is one of the fuel cell killers we care about the most. Often, the catalyst in the anode will have a ruthenium component to it, which gives some tolerance to carbon monoxide. But yes, there are many active projects working on increasing the tolerance to contaminants, which is another way to look at the solution, right? If we can have a fuel cell that doesn't care so much about the contaminants, well, that's great. So absolutely.
Erika Sutherland:
And I think I have time for at least one more question. Is—are any of the large liquid fossil fuel providers part of H2USA or supporting the H2FIRST activities?
Chris Ainscough:
So that's funny you should ask. I was just conversing on email with one of my colleagues at Shell this morning, who's probably on the phone, so hello. So yes. Let's see. Go back here [slide 7]. You can see there are a number of people from the—who are either involved in H2USA or involved in H2FIRST who are helping steer H2FIRST, or being involved in the Coordination Panel. But here's an overview of who the team members are in H2USA right now.
Erika Sutherland:
Sorry. Next question is how is this work related—I think this is our last question here before I turn it back over—but how does this work tie in with the NIST work in terms of weights and measures? I think that's referring to HyStEP.
Chris Ainscough:
So—yeah, so the NIST—so in terms of weights and measures, so there's a project that was run by the California Division of—CDFA, California Division of Agriculture, right, to develop a device to measure the accuracy of hydrogen dispensing. And that is tied—the NIST tie-in here is the NIST 44 Handbook that specifies how accurate the metering must be.
So HyStEP is a different—although the device may look similar probably when it's done, the CDFA work was focusing on accuracy of measuring. So when you go fill up your gas tank, there's always a sticker from the state that says, you know, we've certified this pump. That's what the CDFA and NIST work was about. HyStEP is about making sure that the station follows the fueling protocols, that it follows J2601 and the CSA HGV code, and that it does what it's supposed to, that it communicates with the vehicle, controls the tank temperatures, and responds to leak events the way it's supposed to. So similar, but different goals, really, that are driving them.
Erika Sutherland:
OK. Thank you so much, Chris, for answering all these questions, and Joe. I'm just going to turn it over now to Alli to wrap this up.
Alli Aman:
Thank you so much, Chris and Joe and Erika. Today's webinar was awesome. Just a reminder, everyone on the call, we will be posting slides along with a recording of the webinar in roughly ten business days. I will send an email as soon as they're posted, but I definitely encourage you to check back to our website and sign up for our monthly newsletter. And on that note, I'm going to wrap it up. Thanks so much, you guys.
Chris Ainscough:
Thank you, Alli and Erika and Joe.