Okay, so thank you for that introduction, it's a real pleasure to be here and
be able to give you an update on our GCEP project on Solid Oxide Flow Batteries for
Grid-Energy Storage.
A couple years back, we, we gave a talk as well on the cell material
advancements we've been working on.
In today's talk we're going to focus more on the system concepts,
that will hopefully enable the technology to move it forward.
Before moving into that I just want to acknowledge our team members
PhD student Chris Wendel, Professor Bob Kee at the School of Mines.
Professor Scott Barnett and, and Doctors Gareth Hughes and, and
Zhan Gao at Northwestern are really working at advancing the Cell Technology.
So, in today's talk I'm going to briefly give you an overview of what, exactly,
is this technology.
And followed by, with I guess, I would say our view of some of the motivation and
the technology requirements that are needed for energy storage to move forward.
I'll then move in to some descriptions of reversible solid
oxide cells as flow batteries.
Here we'll look at, little bit at the theory of operation and
performance considerations.
As well as some performance estimates of really these large scale, megawatt size,
gigawatt hours, capacity systems that we would envision for, for bulk storage.
Brief, I'll give a brief update of some of the exciting developments in the South
development area where we're, we're really trying to push towards the 600 in sea
operation salutes and all this GM technology.
And we have some very interesting and encouraging results related to,
to cycling to show of these cells.
And that's very important how we're going to operate forward and
backward modes with this technology.
We don't want degradation there.
Lastly we'll, we'll touch on some of the economic projections for
these kind of large scale bulk energy storage systems.
I'll then briefly touch a little bit on what we've learned, in,
in featured reactions.
So in principle, a solid oxide flow battery really leverages
similarities to fuel cells where we're going to operate reversibly.
Here reversibly is not in the thermodynamic sense.
It's in the sense of reversing the current for the system to operate in a power
producing mode, and in an electrolysis or charging mode.
And we're, we're going to tank the reactants and, and
capture those in, in gaseous storage, and that's particular useful for
us because it gives us really the flow battery advantage.
We get the decouple power capacity from storage.
And so the power will scale with the size of the cell stack and
the energies will scale with the size of the storage tanks.
We also get the high efficiency advantage of solid oxide cell technology.
Which enables us to have really high round-trip
efficiencies as we move between modes.
We don't experience high polarization in electrolysis mode.
And the novel, relatively novel HCO chemistry that is experienced directly
within the cell, allows us to, to produce high energy dense fuels.
So shown here is a, is a, a real simple schematic of,
of a solid oxide cell and oxygen conducting one with some fuel storage.
Here we are showing methane and syngas and we are going to feed it with air, and
we're going to take the oxygen from there, reduce it, get those anions.
Moving and electrochemically oxidized those gaseous reactants into H2O and CO2.
We will capture that gas in a tank and essentially produce our power.
Now, in reverse mode, we can then accept ply voltage,
driver currents, and essentially put our power into the, the device.
And then move into the opposite mode, where we'll remove those previous
products of reaction out of storage back to our cell.
We'll strip out the oxygen.
Liberate some of that oxygen.
And in the meantime, directly within the cell, we will produce methane and, and
syngas.
In general, that'll give us favorable scaling this device, but
also something additionally unique is that it gives us really low-cost working
fluids compared to advanced, and other types of flow batteries.
In terms of motivation, certainly, the variability of renewable energy resources
is is well-known and motivates developing grid-energy solutions.
I like to at least see some picture of what that means?
Here are some minute by minute data shown from Hawaiian Electro Power
on a wind farm.
We can see really a ten exchanged within 30 minutes of, of power requirements.
And it's not just wind variability if we look at developing activities and
concentrating solar power and of course, PV penetration,
they've got power fall-off in, in the evening hours as well that would,
will need to be addressed to get high-capacity factors.
So currently there is no battery technology that really serves
most of our energy storage.
Worldwide is predominantly pumped hydro.
In, that's, but this problem still exists, and those who are facing this,
primarily, often island nations for example, are,
are already trying to develop solutions, and I'll call them poor solutions.
Taking high grade electrical energy, and storing it in low-grade hot water for
example, so called thermal battery.
That's being done by Hawaiian Electro Power to, to manage this,
this variability.
It's also being done in an Electricity Arbitrage Models in Minnesota,
for example.
I've called them the, the dubious honor of having the largest thermal battery in
perhaps in the country at one-gigawatt hours.
High-grade electrical energy,
low-grade hot water is essentially thermodynamic syn.
But in, on the other hand you know,
good economics doesn't necessarily always mean good thermodynamics.
In general,
though, in order to enable that technology we've got to reach some certain targets.
We've been keeping our eye on these as we look at this technology.
Certainly capital cost and round-trip efficiency but perhaps most importantly
some levelized cost of electricity storage around a dime per kilowatt hour cycle.
We need cycle capability, and depending on the application,
you'll need various modes various duration of storage.
If we now turn to looking at the technology itself.
Just operationally, we can take a look at a voltage current
plot which is a representation of the cells performance characteristic.
And shown here, we can see that in power producing mode or fuel cell mode
the voltage will decrease as you increase the current density or, or produce more
power in response to, to overpotentials and irreversibilities within the cell.
The slope of this curve represent the overall resistance.
In fuel cell mode, the higher the voltage the higher the efficiency.
And in electrolysis mode we can see a rel, a relatively smooth transition shown here
in this cartoon, but that's actually what we see experimentally as well.
There isn't a large over potential that gives us good electrolysis efficiencies
low-applied voltage needed there.
But here you want low voltage equals high electricity in electrolysis mode.
So, if we look at the round-trip stack efficiency, which is not shown here, okay.
It's basically the voltage of the fuel cell divided by the voltage
of the electrolysis device.
That's the ratio.
So you want high fuel cell voltage, low electrolysis voltage,
that will give you a high round-trip efficiency.
At the system level we not only need to be mindful of the stack but.
We're moving these reactants back and forth between the tank and the stack and
so there's an auxiliary power component that enters into this ratio.
So, in the end, how we can improve system efficiency.
We can improve the cell by reducing over potential and at the system level,
we got to mindful of the balance of plant and thermal management.
And when we look at thermal management,
one of the unique attributes here is by doing methanation locally,
within the cell and electrolysis mode, we are able to obtain low
electrolysis voltages, get towards a thermal neutral operation, as well.
So, when we look at a fuel cell, it requires heat rejection.
We're air cooled we're operating it at relatively high temperatures.
But in electrolysis this is of course and endothermic process.
It requires a heat source.
As, and we can see that when we reduce H2O that's certainly the case.
We're going to leverage HCO chemistry here and because of the nickel in, in,
in the fuel electrode we can also do heterogeneous chemical reactions and
reduce CO2 as well through H2 and
provide us with some CO which can then be combined with hydrogen to methanate.
Which is highly exothermic, okay?
And that's very nice for us.
Because we have a exothermic local source where we have an endothermic process.
We've got good matching of sources and sinks there.
And ultimately, low temperature is what we would want in relatively high pressure
to achieve that methanation.
One of the considerations we're faced with as well is.
If we're going to design one of these systems, what do we charge the tanks with?
What is the composition we want?
And what are the considerations therein?
So in these systems, we have to be concerned about carbon deposition.
This is a deleterious effect on, on, on, solid oxide cells.
And it degrades their performance rapidly should that happen.
So shown here is in the right is essentially
a compositional space used in a so called Gibs diagram or ternary diagram.
Where the shaded area above the rad indicates the thermodynamically
favorable region for carbon deposition to occur.
And the, the open, the white zone really is is unfavorable for
that, and that's where we want to operate.
So in doing so, you can see the red dot up here is where we might start on
a hydrogen carbon ratio oxygen ratio for, for fuel cell mode.
As we oxidize the fuel, we'll move towards this fully oxidized region shown in
the light blue, and we don't really want to be fully oxidized.
In this system, we want to be not fully oxidized and not fully reduced.
This is our operating window, if you will, to move back and forth.
If we look at the bottom graph, we can see basically on the left hand side
equilibrium gas constitution on a molar basis.
It's, it's a wet basis shown here versus oxygen content.
And we can basically move back and forth between, shown here between 4 and
40% oxygen conversion, which will allow us to have fairly high storage capacity.
We can produce methane in a 60-40 ratio with hydrogen here, on a dry basis.
And at this end of the cell, so basically as you produce a fuel cell mode,
you'll see us reducing the CH4, producing H2O.
These, of course, will be tanked for electrolysis mode.
So one of the proposed applications we've been looking at is really bulk storage.
To, in order to get there, we need very large tanks.
And very large tanks can be realized with pressurized underground
gaseous storage of our reactants.
Using salt caverns, for example, natural gas reservoirs, saline aquifers.
And so we're, this concept is actually being very seriously considered.
Particularly in Europe in, in, in Germany.
And we're looking, in collaboration with the Danish Technical University, at,
at designing this so-called surface system which will, will convert and
store our reactants.
Using, survey data on natural gas, reservoirs in Denmark, for example.
We can estimate 500 gigawatt hours of storage would be available for
one plant that has a 250 megawatt capacity.
And the punch line here is, we'll get to this later.
But in the end, these storage costs can reach $0.03 to
$0.04 per kilowatt hour with storage durations of months.
Which is particularly important.
Germany in particular, very interested in month long duration storage.
Because of the low PV insulation during the winter in particular.
Because we produce methane we find it really interesting if the technology is
also suitable to support the so called power to gas platforms.
They're very of, of increasing interest and particularly by Europe and
getting off of Russian natural gas and using renewable green electricity,
if you will, to make SNG.
This technology is perfectly applicable to that.
In the end, though, we need this top surface system.
And that involves systems integration and thermal management strategies
in moving essentially, between the caverns and the stack.
And so, just very briefly.
We have to pressurize and preheat the reactants that get over to the stack.
We can recover some of that energy from fuel cell exothermic operation
to reduce our balance of plant parasitics.
From the cavern and we'll take our CH4, preheat it, and
expand it because it's operating at say 160 bar and the stack is at 20 bar.
We'll recuperate some power, and we'll introduce steam and
use the tail gas, if you will, of that
process to meet our process heating needs before dumping it into the CO2 cavern.
We'll get DC power out and we go to electrolysis mode,
we basically reverse and store in the CO2 cavern, store in the CH4 caverns.
Importantly, in order to make this viable we want to use the same equipment.
Okay, so, that means they have to be sized and operated and
designed such that that can be done.
We also have to carefully manage water in these systems.
We're going to knock it out and
generate it because we can't really easily store it in these caverns and extract it.
When we look at performance trades, clearly a key issue is what pressure and
temperature should this stack be operated at?
One of the things we like about this project is we get cell material
development, we get systems aspects going on, and
the two get to talk to each other we can say from a systems view.
I don't really need very low temperature or I need a different pressure for
you guys that focus on perhaps, depending on the application.
So here we show a plot of, of roundtrip efficiency for the stack and the system,
we'll just focus on that verses stack pressure.
And we see an optima is here, and
that optima is basically is the interplay between the,
the auxiliary power, depending on what the stack pressure is.
So if the stack pressure is relatively low,
we can get net power out of our system in fuel cell mode.
And that can offset our electrolysis pumping requirements.
In the end, that interplay gives us an optimum of around 20 bar which we like,
because that matches a lot of the high pressure turbine spools that are available
that might be integrated with the system.
Similar trades are present when we look at temperature and reacted utilization.
And, and those optima are shown here.
If we just quickly move into now looking at some of the cell
technology advancements that, that have been ongoing with this project.
We're really focused on these next generation material sets leveraging
really LSGM technology to push toward 600 C and with high cycle durability.
Briefly, here's an SEM image of the microstructure of one of the cells.
And you could see the thick LSGM electrolyte layer.
The dense layer that's, that's right here.
Overall the, the sum of these layers is quite thin.
But you can see here there is on, on, on your,
your air electrode, we have our gas diffusion support.
It's LSF.
We have a nickel infiltrated LSGM fuel electrode that allows us to get high
current densities for high triple phase boundary area, if you will.
This is on an SLT support which gives it strength and
one of it, the unique pieces of this is, is the nano-particle nickel infiltration.
In the fuel electrode.
If we look at the performance characteristics,
we can get the high performance.
High performance here demonstrates at the power density of 1.6 watts
per square centimeter at 650 C.
As far as we know, that's, that's one of the records.
It works in both modes very well.
The area specific resistance is .18.
We've been targeting 0.2 Ohm's square centimeter for the system.
And we've demonstrated that at the, at, at really button cell level.
We have to do better on the 600C
polarization curve if you will that's getting slightly higher.
And we still need better performance there.
But most interestingly,
I think one of the tests that we've been running is on cycle durability.
We, we need to cycle these things forward and backward and
no one has really tested this kind of technology in this mode.
So we've looked here at really one and 12 hour cycles.
You can see a 30 minute operation on one mode, 30 minute operation on the other,
switching back and forth between these modes.
For different cycle times.
So here's is a one hour show, but we've also done 12 hour cycles in as well.
So six hours in one mode,
six hours in the other mode at different operating current densities.
And what you'll notice here is on this light blue curve,
if you're just operating electrolysis mode, you get fairly rapid degradation.
But as we change into cyclic mode,
we get reduced degradation as exhibited by the change in total resistance over time.
And we've tested this for 1000 hours, and as you can see, as,
once you get below a certain threshold, operating current density,
the degradation mechanisms have turned off, essentially, or interrupted.
And we find that that actually happens around .8 amps per square centimeter.
Which is at least twice as high, or about twice as high as we think is
economically needed, to develop the technology.
So we're really encouraged, by these results in particular.
In the remaining minutes, I'd like to give you a little snapshot of the economics,
when we first presented a couple of years back.
There are a lot of questions on that.
We had no data.
I can report some data.
On this, at this time.
And, that's unfortunate.
This okay I'm in IBM PC and, and these equations aren't showing up.
But.
What I would say is briefly there is a simple calculation that basically takes
the it takes the investment cost and
divides by the energy storage in a round trip efficiency in the number of cycles.
And you get essentially a simple storage cost metric.
In sense for kilowatt hour.
The challenge with this method is,
it assumes a hundred percent capacity factor, in doing so.
In order to, be able to perform this, we need to cost out the plant.
So we've done some bottom up plant costing using some of these parameter values.
Here briefly, highlighted here.
250 megawatt rating.
We've shown we can get higher round trip efficiency but we just put in 70% here.
Mature life projections for solid oxide cell technology.
Again, we're using costs from solid oxide fuel cells that are very applicable here.
But perhaps not exactly applicable depending on the cell material sets.
The storage there's a fair amount of good data here.
We've been leveraging existing natural gas reservoir data from Lille Torup facility
in Denmark, 120 million cubic meter natural gas reservoir facility.
We make use of 70 million cubic meters of that.
We need a 50 million cubic meter push in gas to support that activity.
And we've priced out that cost based on the existing cost that we know for
that, that.
And we've extrapolated for CO2 caverns.
There that's relatively unproven storage CO2.
We've essentially taken CH4 costs and more or less double them for the risk.
In the end, we get a capital cost at this scale of around,
less than $1,100 per kilowatt.
If you look at the total expense breakdown up here, it's not just capital costs.
We got operating maintenance cost here and staff and so forth to operate.
But in the end we're about 30% on, on the stack.
In less than 15% in the storage.
With this simple costing method then allows us to get us around $0.03
per kilowatt hour on storage costs with this method, which if you look,
compare favorably against compressed air, air, hydrogen and,
and pumped hydro in these other bulk storage categories.
We think that's, perhaps a little too simple, and, more we can leverage instead,
the resources of this storage facility, using electricity,
spot market prices and essentially, using supply and demand characteristics.
Of the grid market and
do essentially market arbitrage to buy and sell power essentially.
Buy power cheap, charge your system and
sell it when the price of electricity is high.
So the cautionary note here is.
In making these calculations, of course, we knew what the prices were.
It's historic prices and we could optimize the sell-buy strategy
which then means this is really a maximum annual income estimate, okay?
So if we look at 2008 electricity spot mark, market prices,
our colleagues in DTU really performed the study.
They use the Danish market because that's what they were interested at the time with
our system.
And we don't get a capacity factor of 100% in this scenario, we get 61%.
When you look at the life cycle cost,
that raises it from almost $0.03 to almost $0.08.
But you do get revenue from this and you can drop that by 4% to a net
overall storage cost of just under $0.04 at $0.037 per kilowatt hour.
There is lots of considerations that in the future, increasing
renewable energy penetration will mean higher electricity price volatility.
And you could essentially do more arbitrage under those scenarios.
With those scenarios then, there has been because eh,
Denmark in particular is interested in 100% renewables integration by 2035.
They are very seriously looking at then the price impact on their markets, and
they have done scenario forecasting reviews.
Those forecasts with the 2008 buy/sell hour, strategy.
And, we show that under that.
And shown here in the red curve is the buy/sell strategy and, and, and the price,
spot market prices that might be expected in the future.
With high penetration,
you could actually make money with electricity electricity storage.
Again, this is maximum.
And of course there's lots of uncertainties here, but it does suggest
that if you, even if you weren't perfect, you might end up at zero cost on storage. Okay.
So to wrap up here we see
that there are a lot of markets that we could enter within this technology.
Not only the so called power gas platform.
We can do both storage and more recently within the project confines.
We're turning now our attention to distributed scale storage that will
compete with the Vance flow batteries and sodium sulfur batteries in,
in the kilowatt hour to low megawatt hour ranges.
There's a lot of work that certainly needs to be done yet.
We need, really need to push the envelope on the operating temperature further with
the LSGM technology of results shown here are for small scale cells, okay?
Cell scale up is always a challenge and that needs to be done.
Long term stability and durability testing.
We have to operate in cyclic modes with the actual reacting gases we envision.
And of course if you're going to run this thing up and down, you need to know
something about the dynamics of the capability of, of the system.
So, with that I'd say we learned fair amount.
We believe we can get fairly high round trip efficiencies.
We can even get above 80% if you can integrate formally with nuclear CSP,
for example.
And regardless of, of how we, we estimate the economics, we think they're much
they're very attractive and can meet or exceed the DOE targets.
Now with that I'd like to thank some of my collaborators and open it up for
questions.
[APPLAUSE].
>> Questions for Long?
Okay, do the back first so yeah that's easier.
>> Yeah, I have a question about if you guys have any problems with cell ac,
sorry, here.
>> Okay. Sorry. >> With cell activity when you're running in electrolysis mode
to converting the CO2 to methane?
Do you have any issues with making C2s or, you know, products that you don't want?
>> No, actually, the, the electrodes are catalytically active enough that they
reach equilibrium rapidly with, with without even pulling out oxygen.
When you pull out oxygen, obviously we'll drive the equilibrium forward but
we make methane and C O and
H 2 as exactly as you might predict thermodynamically.
>> [INAUDIBLE] >> Nice work Rob.
Can you hear me?
>> Yeah.
>> Nice work.
Can you care about comment about the the caulking problem and whether you
see it more in the, in the electrolysis mode than in the fuel cell mode?
>> That's a good question because as you move from electrolysis mode,
you're moving towards the caulking boundary.
Certainly one of the questions we have is, you know the thermodynamics you know,
is nice, and it provides insight and guidance on how to select conditions.
But you really are dealing with local phenomena when you're flowing these
reactant gases through the passages of the cell, and if you don't have a, a good
distribution, you could have locally rich zone, so to speak, which could,
could produce carbon deposition, which would degrade performance.
So what's not so well known is what we would call the safety margin
that would be required to, to push you away from that thermodynamic boundary.
So what hydrogen and carbon ratio, and
what operating conditions would give you sufficient safety margin to not coke up.
So that, that will be revealed more in the cell testing.
As a part of the project we've built a pressurized rig at Northwestern and
they're going to be operating under
sine gas conditions at pressure and temperature.
And that'll give us some better insight.
Nevertheless, there's still fairly well mixed conditions under the lab,
the lab environment.
>> The back, right there.
>> So how important it is to lower the operating temperature of this devices,
and what do you think is the main idea of in that direction of research?
Or how, how to, how you think you can achieve that goal?
>> Okay. So, lowering the,
the operating temperature really makes more sense.
At the large, bulk scale we don't think we need that lower temperature at this point
but we look at, we start turning towards distributed scale systems.
You know, tens of kilowatts, to hundreds of kilowatts or megawatt.
We, we think we will have, we basically, in order to keep the cost low we want to
strip out a lot of the DOP equipment that we can.
So, we think we can get relatively simple and elegant designs.
However we'd like to avoid pressurization in those situations, as well, and
so shown here for example is a round trip efficiency versus stack temperature.
You do have an expander included, but
you can see that as we lower the stack temperature, we can get close to
78% round trip efficiency at 600 C for one of these small scale systems.
And we really think we need, you know, depending on whether or
not you have the expander you're going to be closer to 70% efficiency if you don't,
but you really need the 600 C.
The barriers are really the polarization resistances that are occur.
The, the resistances go up as you reduce temperature because the ionic connectivity
of, of the cell goes down.
One of the strategies could be to reduce the air electrode polarization resistance.
We think they, they might be able to do that by doing more
nanoparticle infiltration on that electrode.
>> Just like has been doing on the fuel electrode with nickel,
except it might be done with Samaria, for example.
I have a quick question you mentioned in your cost analysis
that your stack probably should last for at least five years.
So could you explore a little bit and
say why you believe it will be as long as five years?
>> Yeah. We don't know how long it will be.
Right now what we see is,
after 1,000 hours in these small scale cell test virtually no degradation.
The challenge is, of course, we have to operate on the carbonaceous
fuel feed stocks we envision, and that hasn't been done over hours.
The cycling doesn't seem,
at this point, okay it seems like it, it, it does have promise.
Other solid oxide cell technology has been demonstrated well past 20,000 hours.
All the developers of that traditional focus and
technology development are, are focused on increasing endurance.
It's going to take certainly several years,
I'm sure, to achieve that, but that's economically what the target has been.
Some cells, like see, old seaman's tubular cells, they lasted 70,000 hours.
But we think 40,000 is where your going to have to start to enter the market place.
That's real consistent with fuel cell technology.
>> Okay, let's thank Bob again.
[APPLAUSE]