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Hydrogenics to supply 1MW electrolyzer to project converting CO2 to methanol; Power-to-Gas

Hydrogenics Corporation will supply a 1MW electrolyzer and provide engineering expertise to a consortium of companies working on the European project MefCO2 (methanol fuel from CO2) in Germany. The application will take excess electricity from intermittent renewable energy sources, generate green hydrogen, and then create methanol using a low-carbon footprint production plant and carbon dioxide emissions from an existing coal-fired power plant in Essen, Germany owned by STEAG Gmbh, which operates a number of regional power plants and distributed energy facilities.

CO2 will be captured from the flue gases in a special downstream flue gas scrubber (Post-Combustion Capture, PCC). The Hydrogenics electrolyzer will produce 200 cubic meters of hydrogen per hour. The hydrogen and captured carbon dioxide will then be catalytically converted into methanol, with a daily yield of approximately one ton of methanol using approximately 1.4 tonnes of CO2.

Although a tried-and-tested process, direct methanol synthesis has not as yet been used in combination with a utility power plant and under load-flexible operations, notes project partner Mitsubishi Hitachi Power Systems Europe (MHPSE). MHPSE is acting as the system integrator.

There is no difficulty to up-scaling the system, MHPSE said. Installations of up to 200 MW can be implemented relatively rapidly and efficiently operated. This kind of large-scale installation would produce up to 180,000 tons of methanol a year and thus stop emissions of up to 260,000 tons of CO2.

This project will use our most advanced PEM technology, developed specifically for utility-scale Power-to-Gas applications, and turn carbon dioxide into energy. Methanol production from green hydrogen represents a very promising way to decarbonize parts of the traditional fuel industry as well as chemical sector. Hydrogenics looks forward to the results of this energy storage demonstration project to further broaden the market for our electrolyzer technology in the production of renewable fuels.

—Daryl Wilson, CEO of Hydrogenics

The MefCO2 consortium consists of Mitsubishi Hitachi Power Systems Europe; the Laboratory of Catalysis and Reaction Engineering of the National Institute of Chemistry Slovenia; the Cardiff Catalysis Institute; Carbon Recycling International; the University of Genoa; the University of Duisburg Essen; i-Deals; and Hydrogenics.

The project has a budget of €11 million (US$12.4 million) and is partially funded by a grant from the EU Horizon2020 research program managed by the Spire public-private partnership. The project will last three to four years and involves the design, building and testing of systems to demonstrate the utilization of surplus and intermittent renewable energy sources and waste CO2 for the production of methanol.



I want people to understand there is NO waste heat from electrolyzers that can be efficiently reclaimed. Electrolysis is an endothermic reaction, it takes IN heat. Fuel cell are and exothermic reaction, the give OFF heat.


The heat chain I outlined uses waste heat at the other end, when hydrogen is being converted back to electricity.

BTW although most home and other fuel cells in use today are pretty much one way, they can also in theory at least be used for the electrolysis, and work is in hand on precisely those reversible cells.


I also am not an engineer, so take this for what it is worth. If electrolysis can be done efficiently, then why not use wind and solar for the base load, excess from wind and solar for electrolysis, and nuclear as steady-state generation, adding to the grid if needed, but otherwise for electrolysis or pyrolysis?


If you build a nuclear plant, that costs a lot of money and fuel and running it near enough to nothing.
That means you want to run it for as many of the 8760 hours a year as possible, and rates of 95% plus are routinely achieved.

So that is 8322 hours a year.

Renewables also tend to cost a lot to build, and little to run, and what is more you can't rely on when they are available.

For the purposes of this blog, the emphasis is on transport, and EP is quite right that if you have the electricity available when you need it, you are better off energetically not fooling around with converting it to hydrogen and back again.

So France, which is the only country with a decent proportion of nuclear power, can simply plug in their BEVs at night when grid demand is lowest, and charge them with only the transmission losses of much account, as since the carbon emissions and running costs are negligible efficiencies at the plant don't matter too much.

Any way you convert that to hydrogen and back does not make sense, as it costs both money and energy.

The case is very different for renewables, as they usually aren't about when you need them and are hugely variable.

Night times don't cause problems which batteries can't solve for solar, although that costs money and energy, the issue is winters outside the tropics.

Wind has similar issues as it is immensely variable, with a hundred times more energy in a gale than a calm.


I lost the thread of the argument.

The point I was going to make is that if you are going to pay for the solar, you have to use that when it is available too.

At, say, 16% capacity, something like US average, that is 1400 hours.
That would reduce the capacity factor of nuclear to at best 85%, in practise less.

That hits the economics of nuclear hard.
Effectively you have to pay for solar as well at nuclear for the same kilowatts, with very small cost savings.

This applies for instance in Germany and the UK, but much less so in the US, as the summer peak is very high for air conditioning, and solar could basically simply take care of that.


Using Solar and Wind for base load is possible if combined with variable Hydro for peak loads and whenever Solar and Wind cannot meet demand.

Hydro's large water reservoirs become the network storage units.

Size and number of water reservoirs, Hydro turbines and REs have to be matched to balance network.

Roger Pham

Hydrogen has LHV (low heating value) meaning the heating value when the exhaust is in the form of steam, containing the latent heat of stam, and
HHV (high heating value) when the exhausting steam gives off all the latent heat and exit as liquid water.

For electricity generation, count on the LHV of H2.
For home and water heating, count on the HHV of H2.
Efficiency of electrolysis is expressed as the HHV of H2 to get a higher efficiency number. The difference HHV and LHV is about 19% (?) HHV / LHV = 1.19.


@Roger, SJC:
Fight it out between you as to what is appropriate to use where, I will hold your coats!

I've got the basic idea behind the values, but to know how they apply and which is appropriate to use needs a far greater level of comprehension than I have.

I am light around 4 years of physics/engineering to understand the subjects well enough to make any worthwhile evaluations, and unless you have enough chops to do a critique, then you should keep quiet, which is what I intend to do! ;-)

Roger Pham

LHV for Hydrogen is 33 kWh per kg, use for calculation of FC and engine efficiency.
HHV for hydrogen is 40 kWh per kg, use for calculation of electrolysis' efficiency and heater's efficiency.

Low-temperature electrolysis requires cooling to remove waste heat at around 80-90 degree C, 75-80% efficient.
Intermediate electrolysis is more efficient at above 90% efficiency, with waste heat at above 100 degree C.

High-temperature electrolysis is what you're referring to, and takes place at 700-800 degree C, using solid oxides to with such a high temp. Could be 130% efficient with respect to electricity energy, by using some thermal energy as well. Still very expensive and still experimental.


LHV doesn't mean low heating value, it means LowER Heating Value.  It is the energy available when the latent heat of water cannot be recovered.  The HighER Heating Value is when the water vapor is condensed.

The difference can be substantial; the LHV for methane is 50.0 MJ/kg, the HHV is 55.5 MJ/kg.  The difference for hydrogen per Roger is a full 20%.

As for the economics issues, all of this is easily solved if people simply pay for what they're actually using.  In the case of nuclear power, what they're getting is an always-on stream of power with extremely low marginal cost.  The way to bill for this is a monthly "subscription fee" for your base load, say as a constant 300 watts 24/7 which you pay for even if you don't take it.  It would be the cheapest dispatchable power you could buy, but the quantity would be limited; additional capacity could be financed by waiting lists for subscriptions.  As you got to more variable demand, you'd trade off availability vs. marginal cost.  If your peak demand was only 1% of the time, you'd be happy with a high marginal cost so long as the availability fee was low.

Where variable renewables fit in this isn't clear-cut, but selling at a spot price would favor users who could buffer their consumption.  Appliances like ice-storage air conditioners, frozen-brine freezers and heat batteries for DHW and space heating would be favored.  All of these things would save people money, and could do so in at least 2 ways:  levelling demand to move more consumption to the subscribed base-load amount, and scheduling demand for periods when surpluses make spot prices cheap.


Good discussion, but I do not see any mention of the problems Germany has been having with the "excess" renewable power. So much so that spot market rates went negative, i.e. generating companies were having to pay others to take their power rather than dial down generation.
I like the concept of trying to solve two problems (disposal of CCS CO2 and variable renewable power) at once, but suspect the economics won't work overall - per comments above about capital cost and utilisation factor. Negative spot market rates are pretty intermittent after all.

Roger Pham

Good point, CJY, the economics will improve with volume and experience. With increasing penetration of renewable energy (RE), there will be no going around the need to store increasing periods of energy excess, for winter heating and power production. The cost will eventually go down to be competitive with fossil fuels. We have got to continue now in order to get to that point. If we don't do anything now, we will never get there.

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