Hydrogen Research and Data

Hydrogen: overview and conclusions?

The best opportunities for hydrogen in the energy transition will be to decarbonize gas at source via blue and turquoise hydrogen, displacing ‘black hydrogen’ that currently comes from coal, and to produce small-scale feedstock on site via electrolysis for select industries. Some see green hydrogen becoming widespread in the future energy system. We think there may be options elsewhere, to drive more decarbonization, with lower costs, lower losses and higher practicality.

(1) Green hydrogen economy? Our main question mark is over “economy”. Costs are modeled at $7/kg, equivalent to $70/mcf natural gas, after generating renewable electricity, electrolysing water into hydrogen and storing the hydrogen. Levelized costs of electricity then reach 60-80c/kWh, for generating clean electricity in a fuel cell power plant, yielding a CO2 abatement cost of $600-1,200/ton (note here). We think costs matter in the energy transition and the entire world can be decarbonized via other means, for an average cost of $40/ton in the TSE roadmap to net zero.

(2) Fuels derived from green hydrogen are by definition going to be more expensive than the hydrogen itself. We have evaluated electro-fuels, green methanol, sustainable aviation fuels, hydrogen trucks, again finding CO2 abatement costs above $1,000/ton. Again, we think transportation can be decarbonized cost-effectively via other means.

(3) How much can capex costs come down? There is an aspiration for electrolyser costs (presently around $1,000/kW on a full, installed basis) to deflate by over 75%. However, we have reviewed electrolyser costs line by line and wonder whether 15-25% deflation is more realistic (note here). Alkaline electrolysers vs PEMs are contrasted here. We have recently screened NEL’s patents to explore future cost deflation in electrolysers.

(4) Efficiency: the second law of thermodynamics. The absolute magic of renewables and electrification is their thermodynamics. These technologies can be 85-95% efficient end-to-end, precisely controlled, and ultra-powerful. A world-changing improvement on heat engines and an energy mega-trend for the 21st century. However, the thermodynamics of hydrogen depart from the trend, converting high-quality electricity back into a fuel. The maximum theoretical efficiency of water electrolysis is 83% (entropy increases). Real world electrolysers will be c65% efficient. End-to-end hydrogen value chains will be c30-50% efficient. We want to decarbonize the global energy system. It therefore seems strange to take 100MWH of usable, high-grade, low-carbon electricity, and convert it into 40MWH of hydrogen energy, when you could have displaced 100MWH of high-carbon electricity directly (e.g., from coal). And all the more so, amidst painful energy shortages.

(5) Backing up renewables? It is often argued that renewables will eventually become so abundant, especially during windy/sunny moments, that the inputs to hydrogen electrolysers will become free. We think this is a fantasy. Instead, industrial facilities and consumers will demand shift. Conversely, we are not even sure an electrolyser can run off of a volatile renewables input feed without incurring 5-10% pa degradation, or worse (if you read one TSE note on green hydrogen, we recommend this one).

(6) Operations, transport, logistics all feel strangely challenging. Our studies of patents suggest that electrolysers and fuel cells can be the Goldilocks of energy equipment. Past installations have declined at over 5% per year. Due to its small molecular size, 35-75% of hydrogen produced in today’s reformers can be lost. Some vehicles seek to store hydrogen fuel at 10,000 psi, which is 1.5x the pressure of hydraulic fracturing. Even in the space industry, rocket makers have been de-prioritizing hydrogen in favor of LNG (!) because of logistical issues. The costs of hydrogen transport will be 2-10x higher than comparable gas value chains, while up to 50% of the embedded energy may be lost in transportation: our overview into hydrogen transport is here, covering cryogenic trucks, hydrogen pipelines, pipeline blending, ammonia and toluene. Is a hydrogen truck really comparable with a diesel truck? (note here, models here). Finally, the gas industry is bending over backwards to stem methane leaks, due to methane’s GWP of 25x CO2, but hydrogen itself may have a GWP as high as 13x CO2.

(7) Will policy help? We are not sure. We are tempted to draw analogies to the Synthetic Fuels Corporation, bequeathed $88bn of US government money in 1980 amidst the oil shocks, which in today’s money is similar to the $325bn Inflation Reduction Act. It completely missed its targets of unleashing 2Mbpd of synfuels by 1992, due to challenging economics, thermodynamics, technical issues, logistical issues. What evidence can we find that green hydrogen will prove different to this historical case study?

(8) Niche applications can however be very interesting, where clean hydrogen is used as an industrial feedstock. An overview of today’s 110MTpa hydrogen market is here and underlying data are here. At large scale, we are currently most excited by using clean hydrogen in ammonia value chains and steel value chains, as the technology is fully mature and looking highly economical. It is also booming in the US. Elsewhere, an excellent large-scale application is to displace black hydrogen (made from coal), which is 20% of today’s hydrogen market and has a staggering CO2 intensity of 25 tons/ton. At smaller scale, there is also a weird and wonderful industrial landscape, using hydrogen to make products such as margarine or automotive glass. Putting an electrolyser on site beats shipping in hydrogen via cryogenic trucks. But these are also quite niche applications.

(9) Blue hydrogen is the most economical, low-carbon hydrogen concept we have found. Effectively this is decarbonizing natural gas at source, by reforming the methane molecule into H2 and CO2, the latter of which is sent directly for CCS. Our best overview of the topic is linked here. There are still c15% energy penalties. Costs are $1-1.5/kg in our models, to eliminate c90% of natural gas CO2.

(10) Turquoise hydrogen is also among the more interesting concepts, pyrolysing the methane molecule at 600-1,200◦C into H2 and carbon black. Our base case cost is $2/kg, with a $500/kg price for carbon black. But if you can realize $1,000/kg for the carbon black, you could give the hydrogen away for free. We have screened patents from Monolith and expect others to come to market with technologies and projects.

Around 40 reports and data-files into hydrogen have led us to these conclusions above; listed in chronological order on our hydrogen category page. The best way to access our PDF reports and data-files is through a subscription to TSE research.

Topsoe: autothermal reforming technology?

Topsoe autothermal reforming technology aims to maximize the uptime and reliability of blue hydrogen production, despite ultra-high combustion temperatures from the partial oxidation reaction, while achieving high energy efficiency, 90-97% CO2 capture and <1 kg/kg CO2 intensity. This is achieved via twelve technology innovations.

Topsøe is a chemicals technology company, privately owned, headquartered in Denmark, founded in 1940, with 2,400 employees, $1bn of revenues in 2022 and 10% EBIT margin.

Topsoe’s technology focuses include gas reforming into syngas, comprising hydrogen and carbon monoxide; downstream value chains that use the components such as refinery processes, renewable fuels, low-carbon hydrogen, ammonia, dimethyl ether, methanol, synthetic natural gas and sulfuric acid.

This data-file is focused on Topsoe autothermal reforming technology, for the production of blue hydrogen, which matters increasingly as blue ammonia and blue steel value chains start booming in the US.

Topsoe’s ATR design, called SynCor, has been deployed commercially since 2002, and may be leading ATR technology in the marketplace in the early-2020s. Some examples of commercial deployments are noted in the data-file.

Advantages of Topsoe’s ATR technology are said to include high uptime, “best in class” energy intensity, 90-97% CO2 capture, <1 kg CO2/kg H2. But how is this being achieved, and how much of it is patent protected?

The first step of blue hydrogen reforming is a partial oxidation reaction, combusting methane with pure oxygen from an air separator, to produce CO and H2. This burner runs extremely hot. Flame temperatures reach 2,500-3,000ºC, and even by the upper portions of the catalyst bed, temperatures are still 850-1,100ºC.

High temperatures in context? You can compare this with the heating-melting temperatures of materials, maximum temperatures of structural materials, typical combustion temperatures, typical refinery processes and the hottest gas turbines.

These high temperatures cause unavoidable volatilization of materials, even refractory lining materials. Volatilized materials are later prone to being deposited on the catalyst beds. Or catalysts may be directly deactivated by exposure to excessively hot temperatures. Conversely, protecting the catalysts from very high temperatures causes pressure drops and energy penalties.

Overall, this means that key challenges for blue hydrogen reactors include reliability, uptime and maximizing energy efficiency.

Twelve innovations from Topsoe are discussed in the data-file, to address these challenges. In each case, we have aimed to explain what the innovation is, why it matters, and whether we can find support for the innovation via Topsoe’s patents.

There are alternative designs for blue hydrogen production, however our patent review leads us to wonder whether they will have lower rates of CO2 capture (e.g., KBR technology) or lower uptime and resiliency.

Our updated model of blue hydrogen costs integrates some of the considerations from this data-file and blue hydrogen technology review.

Combustion fuels: density, ignition temperature and flame speed?

The quality of a combustion fuel comes down to its physical and chemical properties. Hence the purpose of this data-file is to aggregate data into different fuels’ combustion properties, such as their energy content (kg/m3), energy density (kWh/kg, kWh/gal), flash point (ºC), auto-ignition point (ºC) and flame speed (m/s, cm/s). Conclusions about high quality fuels follow.

Gasoline is an excellent transportation fuel. A high energy density of 36 kWh/gal yields a high vehicle range. A low flash point of -40ºC means it is easy to start an engine, even in the dead of winter. A low auto-ignition point of 250ºC means near-complete combustion will occur in an engine cylinder, even one with cold spots. And finally, a high flame speed (0.4 m/s at STP) enables high-RPM engine performance.

Other hydrocarbons have similar properties to gasoline, with high energy densities, low auto-ignition temperatures and high flame speeds.

Natural gas (methane) has the lowest flash point, at -188ºC but one of the higher auto-ignition temperatures of 540ºC, making it well suited to stationary power generation, with fast ramp rates.

Conversely, marine fuel oil has a high flash point, around 85ºC, which limits fire risk. But combustion slip can be an issue in marine engines. Diesel is similar, famously ignited not by a spark plug, but by high pressures in the Otto Cycle.

Solid fuels generally have slower combustion. And more variable combustion conditions, depending on the degree to which they are dried and pulverized.

A typical coal grade might need to be heated above 400ºC to ignite, auto-ignition is at 500ºC, and flame speeds will be 50% lower than hydrocarbons. This makes it slower to ramp up steam engines and steam power plants.

Lower carbon fuels have lower energy density and more variable combustion qualities. Lithium ion batteries have an effective energy density 80-90% below hydrocarbons.

Hydrogen also has low energy density, even when ultra-compressed to 700-bar, while hydrogen also has the lowest flash point of any gas, at -250ºC, explaining a very heavy focus on safety, when we have reviewed hydrogen patent libraries (e.g., NEL).

Ammonia is a possible candidate for a low-carbon fuel, as the combustion of NH3 emits no CO2. Ammonia can be liquid so that its energy density is only 50% below hydrocarbons. But it has one of the highest flash points (130ºC) of any fuel, and one of the lowest flame speeds (80% below hydrocarbons). This creates risks of combustion slip, lower engine responsiveness and the need for a pilot fuel to start up ammonia burners.

Clean methanol is suggested as a better blending alternative to ammonia, as it has a flash point closer to 10ºC and a flame speed similar to liquid fuels (TSE research here).

Blue ammonia: options strategy?

Blue ammonia can economically decarbonize the fertilizer industry, using low-cost natural gas; with options to decarbonize combustion fuels in the future. This report covers where we see the best opportunities, as reforms to the 45Q have already kick-started a 20MTpa boom of new US projects.

Sabatier process: synthetic natural gas costs?

The Sabatier process combines CO2 and hydrogen to yield synthetic natural gas using a nickel catalyst at 300-400˚C. Synthetic natural gas costs $100/mcf in order to generate a 10% IRR, energy penalties exceed 75% and CO2 abatement cost is $2,000/ton?

Synthetic natural gas could be a green hydrogen carrier in the vicinity of gas pipelines and LNG value chains? Or it could be modified to increase the yields of methane in biogas, which typically contains 30-40% CO2 in the mix?

However we think costs will be very high. Our base case economics require a gas price of $100/mcf to earn a 10% IRR, off of capex costs in the range of $1,100/Tpa, slightly higher than a LNG plant but lower than a petrochemicals plant (models here).

Costs are 90% dominated by green hydrogen input costs, which we have penciled in at $7.5/kg, in line with other green hydrogen electrolyser economics. Another $3/mcf of the cost is from sourcing CO2 from an amine plant, or you could source the CO2 from direct air capture.

Total energy efficiency is low, most likely below 25%, as we think that an electrolyser will have 65% efficiency producing hydrogen, while there are side-reactions in the methanation plant (forming CO + H2O, C + H2O or C2H6 + H2O).

This data-file allows for some approximate stress-testing of the Sabatier process economics and synthetic natural gas costs. We think there may be some niche uses of power-to-gas or power-to-liquids technologies, but other decarbonization technologies may prove to be more economical and practical in our own roadmap to net zero.

NEL: green hydrogen technology review?

NEL is a green hydrogen technology company, headquartered in Oslo, listed since 2014, and employing 575 people. It has manufactured 3,500 electrolyser units, going back to 1927, historically weighted to alkaline electrolysers, and increasingly focused on PEMs and hydrogen fuelling stations. This NEL technology review explores its patents.

NEL states that it has more than 100 active patents. And we were able to locate about 100 patents, across 28 families, in the EspaceNet database. In this NEL technology review, we have assessed NEL’s patents using our usual framework.

A large majority of NEL’s recent patents are focused on hydrogen fuelling stations, including compression, storage tanks, safety features, cooling the hydrogen stream, testing the fuelling stations and other components in the balance of plant.

While these patents are high quality, they also give some very candid details over inherent challenges for hydrogen as a transportation fuel. A hydrogen vehicle typically stores hydrogen at 700-bar, so that densities can reach 40kg/m3. By contrast air and CO2 at 700-bar reach 500 and 1,100 kg/m3. Gasoline at 1-bar is 750kg/m3 (chart below, data here).

Fuelling station innovations. Compression takes energy, repeated stop-starts are inefficient and cause wear in compressors, while compressing gases makes them hot, and hot hydrogen is explosive. There are good innovations to address these challenges.

Electrolyser innovations are also found in the patents. Two innovations stand out in particular. One is a nickel mesh, disposed between the electrodes and bipolar plates, which improves efficiency while being easier to manufacture. The other is a specialized frame for alkaline electrolysers, made from thermoplastic, which allows easier manufacturing, better electrical insulation and lower risks of leakage in pressurized cells.

Crucial issues. There is a crucial detail about these electrolyser patents that we think decision makers may wish to explore. This is covered in the data-file. Further information into green hydrogen economics and prospects can be found in our hydrogen overview.

Energy policy: unleashing new technologies?

Does unprecedented policy support inherently de-risk new technology? This 10-page note is a case study. The Synthetic Fuels Corporation was created by the US Government in 1980. It was promised $88bn. But it missed its target to unleash 2Mbpd of next-generation fuels by 1992. There were four challenges. Are they worth remembering in new energies today?

Costs of hydrogen from coal gasification?

What are the costs of hydrogen from coal gasification? This model breaks down the economics, line-by-line, across different plant configurations, backed up with data from half-a-dozen technical papers. We think black hydrogen costs $1-2/kg, but CO2 intensity is very high, as much as 25 tons/ton. It can possibly be decarbonized resulting in semi-clean hydrogen costing c$2.5/kg.

SynGas is a mixture of hydrogen, carbon monoxide and CO2 that is produced by heating coal to around 1,400ºC in an oxygen-limited reactor. The process goes back to 1792, where it was used to produce ‘town gas’. Today, there are over 500 coal gasifiers operating in the world, largely in China and South Africa.

In our base case model, we think that a typical syngas plant must charge around $500/ton, in order to generate a 10% IRR. The syngas can then be used in making chemicals (c50% of the syngas market, e.g., ammonia, methanol), for fuels (c30%), or combusted in a power plant (c20%).

However, CO2 intensity is very high, as much as 0.6 kg/kWh-th, 3x more than natural gas CO2, 1.5x more than average coal grades. Making syngas is only c70-80% efficient at harvesting the energy from coal, which is why the CO2 intensity of syngas is higher than coal itself. Moreover, the product is already partly oxidized (it contains CO), so it releases less energy when it is combusted.

Pure hydrogen can also be separated out from the syngas, by promoting the water-gas-shift reaction, then removing all of the impurities and acid gases. This is referred to as ‘black hydrogen’. We think a 10% IRR requires a hydrogen price of $1-2/kg. But again, CO2 intensity can be astronomically high, as much as 25 tons of CO2 per ton of hydrogen (i.e., 25 tons/ton). This is 3x more than generating hydrogen from steam methane reforming of natural gas (grey hydrogen). Please see our overview of hydrogen technologies.

As part of the energy transition, preserving a future for clean coal, it is feasible to purify and dispose of >90% of this CO2 from producing black-brown hydrogen. The result is a low-carbon hydrogen resource, maybe around 0.06kg/kWh-th. It is possible. But there is a lot of CO2 to dispose of, amplifying costs. The process could be economical at around $2.5/kg hydrogen, we estimate ($22/mcf-equivalent). Details are in the model. But we still prefer blue hydrogen and turquoise hydrogen as leading options.

The costs of syngas and the costs of hydrogen from coal gasification depend on input variables. Capex costs are usually around $1,000/kWth of syngas. Other inputs are coal prices, efficiency factors, chemicals costs, labor costs and other variables. These can be stress-tested in different tabs of the data-file. Data from technical papers are tabulated in half-a-dozen back-up tabs.

Green hydrogen: can electrolysers run off renewables?

What degradation rate is expected for a green hydrogen electrolyser, if it is powered by volatile wind and solar inputs? This 15-page note reviews past projects and technical papers. 5-10% pa degradation rates would raise green hydrogen costs by $1/kg. Avoiding degradation justifies higher capex, especially on power-electronics and even batteries?

Hydrogen: what GWP and climate impacts?

This data-file aggregates technical data into the Global Warming Potential (GWP) of hydrogen, in order to draw conclusions for decision-makers in the energy transition. So what is hydrogen GWP versus methane?

(1) Hydrogen is not a direct GWP, as H-H bonds in the hydrogen molecule do not directly absorb infrared radiation, indeed nor do other symmetrical diatomic molecules like N2 or O2 (no permanent dipole moments).

(2) But hydrogen is an indirect GWP, as it breaks down in the atmosphere over 1-2 years, and its reaction products increase the GWP impacts of other GHGs, such as methane, tropospheric ozone and stratospheric water vapor.

(3) The best estimates we have tabulated in our data-file give a 100-year GWP for hydrogen that is 11x stronger than CO2 and for methane that is 34x stronger than CO2 (please download the data-file for the details).

(4) Concerns? In other words, if you are worried about the climate impacts of leaking 0.6 – 3.5% methane across global gas value chains, the climate impacts are effectively the same for leaking 2 – 10% hydrogen across a hydrogen value chain.

(5) 3x higher hydrogen leakage rates are not an unjustified concern, because the radius of an H2 molecule is about 3x smaller than the radius of a CH4 molecule, and the boiling point is -253C (versus -162C for methane) resulting in more boil-off, and thus upper estimates for H2 leakage rates as high as 20% have crossed our screen.

(6) The hydrogen industry might adapt: by monitoring and mitigating its leakage rates, much like the gas industry needs to do; and by preferring shorter and simpler value chains, direct substitution for pre-existing hydrogen in industry; or transporting hydrogen in carrier molecules (toluene, ammonia, electrofuels are less likely to result in hydrogen emissions, even if they are more expensive).

(7) CH4 Condemnation? Over 50% of the GWP impacts of hydrogen arise because hydrogen mops up hydroxyl radicals, which in turn, prevents these hydroxyl radicals from breaking down methane molecules. Thus the 100-year warming impacts of methane are exacerbated. In other words, the climate impacts of atmospheric hydrogen directly link to the atmospheric impacts of methane. The more worried you are about one, then logically, the more worried you should be about the other. Hydrogen and methane are “in it together” when it comes to GWP.

(8) CH4 Collaboration. Atmospheric methane is around 1,900 ppb, 160% above pre-industrial levels. Every year, about 40% of the world’s methane emissions comes from natural sources like wetlands, 25% from agriculture, cow burps and rice, 25% from coal, oil and gas and c10% from waste landfills. H2’s GWP can be improved by encouraging better methane management in all of these other categories.

Recent Commentary: please see our article here.

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