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.

Vehicle depreciation rates: EVs versus ICEs?

This data-file quantifies vehicle depreciation rates for EVs versus ICEs, by compiling the pricing for over 2,500 vehicles, from various used car websites. Vehicle depreciation rates average $0.11/mile (0.5% per 1,000 miles) for ICE vehicles and $0.27/mile (0.75% per 1,000 miles) for EVs, suggesting that EVs do depreciate faster.

The average costs for ICEs and EVs in the US in 2024 are $30k and $45k respectively, both on a top-down basis when we sample the prices of different vehicles, and on a bottom-up basis when we quantify the underlying costs of vehicles by component. This informs our outlook for vehicle sales over time.

But how quickly do different vehicles lose value? To answer this question, we have compiled data from over 2,500 vehicles, from various used car websites, based on their make, model, delivery year, age and mileage. Interestingly, depreciation rates are similar to or higher than fueling costs!

Vehicle costs per mile for ICE cars, ICE SUVs, small battery hybrids, and EVs.

Vehicle depreciation rates average $0.12/mile for ICE vehicles, which is a depreciation rate of 0.5% per 1,000 miles, and means that a car has lost c40% of its value after 100,000 miles. These kinds of numbers are exemplified by the data shown below, capturing the depreciation of a Honda Accord (Rob’s childhood car!)

Vehicle depreciation rates average $0.27/mile for electric vehicles, which is a depreciation rate of 0.75% per 1,000 miles, meaning an EV has lost 50% of its initial value after 100,000 miles. This is an average across eight well-known EVs, nicely exemplified for the Kia EV6 below.

However, there is also variability among the depreciation rates of vehicles, especially electric vehicles. Generally, the more expensive and more premium vehicles depreciate faster, even in percentage terms (44% correlation). Although the cult following of the Tesla results in lower depreciation rates for the Model 3 and Model Y, which are only slightly higher than for ICEs.

Full data are available in the data file for the BMW i4, Chevrolet Bolt, Chevrolet Equinox, Honda Accord, Honda Civic, Hyundai IONIQ 5, Kia EV6, Nissan Rogue, Subaru Outback, Tesla Model 3, Tesla Model X, Tesla Model Y, Toyota Camry, Toyota Corolla, Toyota RAV4, Volkswagen ID.4.

Results are very similar to a prior analysis that we undertook in 2020, which show the exact same depreciation rate for cars (in $/mile) and a similar depreciation rate for electric vehicles (although the loss rate has increased by c10% in $/mile terms).

Costs per mile of SUVs, hybrids, EVs, and hydrogen cars

In this earlier study, we also evaluated trucks and hydrogen vehicles. The original analysis is also available via the second download radio button below, for those who wish to compare the changes over time.

Vehicle costs per mile for different types of vehicles.

Air Products: ammonia cracking technology?

Can we de-risk Air Products’s ammonia cracking technology in our roadmaps to net zero, which is crucial to recovering green hydrogen in regions that import green ammonia from projects such as Saudi Arabia’s NEOM. We find strong IP in Air Products’s patents. However, we still see 15-35% energy penalties and $2-3/kg of costs in ammonia cracking.

Air Products is an industrial gas giant, listed in the US, with 23,000 employees, producing atmospheric gases, operating 100 hydrogen plants with 3bcfd of capacity and a 600-mile pipeline network on the Gulf Coast, helium and LNG process technologies. It is expanding into blue hydrogen and green hydrogen + hydrogen transport.

The NEOM Green Hydrogen project in Saudi Arabia aims to export 1.2MTpa of green ammonia, derived from 220kTpa of green hydrogen, in turn derived from 4GW of wind and solar, with total capex of $8.4bn.

However, the part of the hydrogen->ammonia->hydrogen value chain that has seemed most challenging to us is in cracking ammonia back into hydrogen. The key challenges for ammonia cracking are energy intensity, costs, longevity and impurities.

Hence in this data-file, we have assessed Air Products’s ammonia cracking technology. The patents are high-quality: clear, specific, intelligible, focused and manufacturable. Hence we think Air Products has invested material time and effort in optimizing the ammonia cracking process, and has built a moat around its technology.

Specific details in the data-file focus on catalyst compositions (patented), heat recapture (patented), ammonia recirculation (patented), product purification (patented), breaking down impurities (patented), avoiding various impurities, avoiding nitriding (patented), and integration with hydrogen fueling stations (patented).

But overall, the details in the patents also remind us how complex the process of ammonia cracking back into hydrogen really is. We estimate gross energy penalties equivalent to using up around 25% of the ammonia that is imported, and net energy penalties of 15% (after reflecting the higher energy content of hydrogen versus ammonia).

Energy penalties and efficiencies for ammonia cracking.

The costs of cracking ammonia into fuel-cell grade green hydrogen are modeled in the range of $2-3/kg, both in this model, and in our model of hydrogen transportation.

Hydrogen: lost in transportation?

Natural hydrogen: going for gold?

Variations of gold hydrogen costs and CO2 emissions compared to other hydrogen production methods. Numbers look promising but there are reasons to be skeptical.

Vast quantities of hydrogen are produced in the Earth’s subsurface, via the Serpentinization of iron-containing Peridotite rocks. Gold, white and orange hydrogen variations aim to harness this hydrogen. This 19-page note explores opportunities, costs and challenges for harvesting H2 out of natural seeps, hydrogen reservoirs or fracking/flooding Peridotites.

Cemvita Factory: microbial breakthroughs?

Cemvita is a private biotech company, based in Houston, founded in 2017. It has isolated and/or engineered more than 150 microbial strains, aiming to valorize waste, convert CO2 to useful feedstocks, mine scarce metals (e.g., direct lithium extraction) and “brew” a variant of gold hydrogen from depleted hydrocarbon reservoirs. This data-file is our Cemvita Factory technology review, based on exploring its patents.

Microbes can be engineered and cultivated to catalyze specific chemical reactions, in bio-reactors, when fed with nutrients (sugars, proteins, salts).

One reaction is the fixation of carbon from CO2, although this does invariably involve supplying energy to overcome the strong 799kJ/mol enthalpies of C=O bonds (O=O is just 498kJ/mol).

Bond enthalpies of common single and double bonds, and the Nitrogen triple bond, in kJ per mole.

In depleted oil wells, unrecovered hydrocarbons can be decomposed into CO2 and hydrogen, and Cemvita’s spin-out, Gold Hydrogen, has made headlines describing trial results in the Permian.

However, we think the reactions that Cemvita is trying to catalyse are mostly endothermic, and would therefore need to be energized by nutrients fed to the microbes. For example, if the nutrients are sugar solution, then $500/ton sugar is akin to sourcing input energy at a relatively expensive 11c/kWh-th. Including inefficiencies and side reactions, the resultant energy costs of hydrogen production are quantified in a tab of the model.

We were not entirely able to de-risk Cemvita’s aspirations for sub-$1/kg gold hydrogen, based on our Cemvita Factory technology review, which evaluated the disclosures in its patents. There were specific issues with economics and additives, and the purity of CO2 that is generated (some very granular details are available in the data-file).

The Patents tab contains a concise summary of each patent we reviewed, its aims, what is patented, and our observations. The wide breadth was notable compared to other patent libraries that we have reviewed.

Please also see our broader research into gold hydrogen and direct lithium extraction. We still think that pre-existing technologies, in both spaces, have a long runway ahead, without necessarily being disrupted. Other engineered hydrogen approaches have interested us.

Natural hydrogen: going for gold?

Direct lithium extraction: ten grains of salt?

Gold hydrogen: the economics?

Economic model for white hydrogen production in the best case scenario.

Gold hydrogen could be recovered from the Earth’s subsurface, with costs ranging from $0.3-10/kg, and CO2 intensities of 0.2-5.0 kg/kg. This data-file models the economic costs of gold hydrogen, and its sub-variants such as white hydrogen and orange hydrogen.

Gold hydrogen denotes a constellation of possible hydrogen resources, that could be recovered from the Earth’s subsurface, analogous to the production of natural gas, with an upfront development capex, production profile, opex and other purification costs.

This data-file models the costs of gold hydrogen, and sub-variants such as white hydrogen and orange hydrogen. We have drawn on our models of shale gas production, other gas field production, pressure swing adsorption, gas dehydration, gas sweetening, gas pipelines, shale CO2 and broader CO2 of producing natural gas.

White hydrogen denotes the recovery of hydrogen from a natural hydrogen reservoir, via drilling and completing production wells, then separating gases at the surface. The best white hydrogen resources could cost $0.4/kg with a CO2 intensity below 0.4 kg/kg. This is materially better than today’s grey hydrogen from steam methane reforming. Although the numbers inflate with higher-cost wells and lower-purity hydrogen (sensitivity analysis below).

H2 price needed for a 10% IRR for a white hydrogen project depending on H2 percentage in the reservoir gas. The different lines are for well capex costs.

Orange hydrogen denotes an engineered approach, where water is injected into fractured reservoirs of ultra-mafic peridotites, where Fe(II) oxidizes into Fe(III), and thereby reduces water into hydrogen, which in turn can be recovered back to the surface. Orange hydrogen could be recovered at a cost of $1.5/kg, in extensive and naturally-fractured greenstones. The economics depend on the ratio of hydrogen resources to total project capex, at $0.4/kg in our base case.

A shale-type approach to orange hydrogen is also modelled, where a horizontal well is drilled into ultra-mafic peridotites, then fractured, then flowed back. Costs are higher here, likely in the range of $2-7/kg. Lower costs are possible in theory, but hinge on extensive fracturing along very long laterals, which would simultaneously need to be lower-cost than equivalent horizontal wells in today’s shale industry.

H2 price needed for a 10% IRR for an orange hydrogen project depending on well lateral length. The different lines are for total capex.

The costs of gold hydrogen can be stress-tested in the model, to interrogate the relationships between input variables and hydrogen economics. For all of the tabs in the model, you can vary the capex, purity and flow-rates of hydrogen wells. For the orange hydrogen play-types, you can vary ten variables into the composition of the peridotites.

For further discussion, please see our 19-page report into gold hydrogen opportunities, costs, CO2 intensities and challenges.

Natural hydrogen: going for gold?

Bright green hydrogen from biomass gasification?

Woody biomass can be converted into clean hydrogen via gasification. If the resultant CO2 is sequestered, each ton of hydrogen may be associated with -20 tons of CO2 disposal. The economies of hydrogen from biomass gasification require $11/kg-e revenues for a 10% IRR on capex of $3,000/Tpa of biomass, or lower, with CO2 disposal incentives.

Bright green hydrogen can be produced from woody biomass that would otherwise have decomposed, partially combusting it at 800ºC with pure oxygen, and generating hydrogen and CO2 for disposal.

Mass balances. If the partial oxidation of biomass is followed by a water-gas shift reactor, plus purification via pressure swing adsorption, then per ton of input biomass, it can yield 0.07 tons of 97-99% pure hydrogen and 21 tons of 95-99% CO2 for disposal.

In other words, biomass gasification can yield clean hydrogen as a feedstock or fuel, but it also sequesters the carbon in biomass, addressing challenges over the permanence of some nature-based CO2 removals.

The economics of biomass gasification are modelled in this data-file, albeit screening as somewhat expensive, requiring $11/kg hydrogen-equivalent revenues to earn a 10% IRR at a gasification plant with capex of c$3,000/Tpa of biomass.

50% of the total costs are associated with covering the high capex costs, while another 5-15% ($1/kg each) can be ascribed to plant maintenance, sourcing biomass and sourcing oxygen.

$11/kg hydrogen-equivalent revenues, in turn, may be derived via any mix of hydrogen revenues and CO2 disposal revenues, such as $11/kg hydrogen and $0/ton CO2 disposal, $9/kg hydrogen and $100/ton CO2 disposal, or $1/kg hydrogen and $500/ton CO2 disposal.

Costs of hydrogen from biomass gasification could best be reduced by reducing the capex costs of gasification facilities. Note the wide range of proposed capital investment costs in the chart below.

Energy economies are c50% energy-efficient, requiring 70 kWh of input energy per kg of hydrogen output, of which 94% is from the exothermic partial oxidation of woody biomass. Another c3% is from separating out oxygen, and another 3% is for compressing CO2.

Hence overall, gross CO2 emissions should be below 1 ton of CO2 per ton of hydrogen, while net CO2 emissions should be -20 tons of CO2 per ton of hydrogen production.

Biomass gasification adds to our list of hydrogen technologies, from black hydrogen, grey hydrogen, SMR blue hydrogen, ATR blue hydrogen, turquoise hydrogen, MIRALON process, chemical looping combustion, and green hydrogen.

Nafion membranes: costs and hydrogen crossover?

Perfluorinated sulfonate (PFSA) membranes, such as Nafion, are the crucial enabler for PEM electrolysers, fuel cells and other industrial processes (e.g., chlor-alkali plants). The market is worth $750M pa. The key challenges are costs, longevity and hydrogen crossover (in mA/cm2), which are tabulated in this data-file.

Nafion was first synthesised by Walther Grot, of E.I. DuPont de Nemours in the 1960s, as a robust cation exchange membrane for the chlor-alkali process, which had previously used materials such as asbestos to separate the anode and cathode sides of the cell.

Today, Nafion’s original patents have expired, and other producers besides Chemours produce PFSA polymers, under various different brand names. But in this article, we will refer to Nafion as a catch-all for similar PFSA membranes.

Nafion turns out to be a remarkable polymer, the enabling membrane for proton exchange membrane electrolysers and fuel cells. It consists of a fluorinated polymer (PTFE) backbone, off of which branch ether groups, connecting to further fluorinated polymers, ultimately terminating in sulfonate groups (SO3H).

Illustration of the chemical structure of Nafion membranes.

The sulfonate groups are strongly polar, exhibiting surface ultrastructural properties that “appear utterly unlike anything else”. They absorb water and form helical channels of 2-3 nm diameter, through which protons can ‘hop’. So can other small cations. But anions and gases are impeded. This is even the reason that the SpaceX’s Dragon space probe used Nafion membrane to dehumidify air against a vacuum.

Costs of Nafion membranes are estimated at $2,000/m2, based on data-points from online sources and technical papers. Thus the membranes will comprise $100/kW of cost in an electrolyser at 1,000 mA/cm2. This feeds into our electrolyser cost model, and the numbers can be stress-tested in this data-file.

The key challenge with Nafion and other PFSA membranes in a hydrogen electrolyser is hydrogen crossover. For example, this means that H2 forming at the cathode of an electrolyser can diffuse back across the membrane in very small quantities, towards the anode side, and re-oxidize into H2O. This hurts Coulombic efficiency by 0.1-1%.

But the more pressing challenge of hydrogen crossover is that hydrogen oxidation at the electrolyser anode will form not only water, but also peroxide radicals, which then have an annoying habit of degrading catalysts in the anode, the membrane itself, and other cell components.

Hydrogen crossover increases linearly with temperature, with H2 partial pressure (itself a function of current density!), for thinner membranes (which have lower resistance and are aimed at maximizing efficiency), and finally with age. Older or degraded membranes have 2-10x higher hydrogen crossover.

Membrane degradation may thus count against putting electrolysers and fuel cells into mobile applications, such as hydrogen cars, hydrogen trucks and planes. For more details, see our overview of electrochemistry and our overview of electrolyser degradation. Details on hydrogen crossover and possible solutions are in the data-file.

Electrochemistry: redox potential?

A flow chart depicting the calculation of a batteries current, voltage, and efficiency providing an overview of electrochemistry.

Batteries, electrolysers and cleaner metals/materials value chains all hinge on electrochemistry. Hence this 19-page note explains the energy economics from first principles. The physics are constructive for lithium and next-gen electrowinning, but perhaps challenge green hydrogen aspirations?

Density of gases: by pressure and temperature?

The density of gases matters in turbines, compressors, for energy transport and energy storage. Hence this data-file models the density of gases from first principles, using the Ideal Gas Equations and the Clausius-Clapeyron Equation. High energy density is shown for methane, less so for hydrogen and ammonia. CO2, nitrogen, argon and water are also captured.

The Ideal Gas Law states that PV = nRT, where P is pressure in Pascals, V is volume in m3, n is the number of mols, R is the Universal Gas Constant (in J/mol-K) and T is absolute temperature in Kelvin.

The Density of a Gas can be calculated as a function of pressure and temperature, simply by re-arranging the Ideal Gas Law, where Density ρ = P x Molecular Weight / RT. Our favored units are in kg/m3.

Density of methane in kg/m3 and kWh/m3

The Density of Methane (natural gas) can thus be derived from first principles in the chart below, using a molar mass of 16 g/mol, and then flexing the temperature and pressure. This shows how methane at 1 bar of pressure and 20ºC has a density of 0.67 kg/m3. LNG at -163ºC is 625x denser at 422 kg/m3. And CNG at 200-bar has a density of 180kg/m3.

The Energy Density of Methane can thus be calculated by multiplying the density (in kg/m3) by the enthalpy of combustion in kJ/kg, and then juggling the energy units. A nice round number: the primary energy density of methane is 10 kWh/m3 at 1-bar and 20ºC, increasing with compression and liquefaction. CNG at 200-300 bar has around 30-60% of the energy density of gasoline, in kWh/m3 terms.

The energy density of methane is 10kWh/m3 as a nice rounded rule-of-thumb.

Clausius-Clapeyron: gas liquefaction?

Methane liquefies into LNG at -162ºC under 1-bar of pressure. The boiling points of other gases range from water at 100ºC, ammonia at -33ºC, CO2 at -78ºC, argon at -186ºC, nitrogen at -196ºC to hydrogen at -259ºC. This is all at 1-bar of pressure.

However, liquefaction temperatures rise with pressure, as can be derived from the Clausius-Clapeyron equation, and shown in the chart below. At 10-20 bar of pressure, you can liquefy methane into ‘pressurized LNG’ at just -105 – 123ºC, which can sometimes improve the efficiency of LNG transport. This can also help cryogenic air separation.

Density of CO2: strange properties?

The Density of CO2 is 1.87 kg/m3 at 20ºC and 1-bar of pressure, which is 45% denser than air (chart below). But CO2 is a strange gas. It cannot exist as a liquid below 5.2 bar of pressure, sublimating directly to a solid. CO2 can also be liquefied purely by compression, with a boiling point of 20-80ºC at 30-100 bar of pressure.

Density of Gas — Density of CO2 according to pressure and temperature in kg per m3

Hence often the disposal pipeline in a CCS or blue hydrogen value chain may often be pumping a liquid, rather than flowing a gas. And finally, these properties of CO2 open the door to surprisingly low cost CO2 transport by truck or in ships. This is all just physics.

Super-critical fluids: fourth state of matter?

There is also a fourth density state for all of the gases in the data-file. Above their critical temperature and critical pressure, fluids ‘become super-critical’. Sometimes this is described as ‘having properties like both a gas and liquid’. Mathematically, it means density starts rising more rapidly than would be predicted by the Ideal Gas Equations.

Super-critical gases behave unpredictably. Their thermodynamic parameters cannot be derived from simple formulae, but rather need to be read from data-tables and/or tested experimentally. This is why the engineering of supercritical systems tends to involve supercomputers.

Examples of super-critical gases? Steam becomes supercritical above 218-bar and 374ºC. CO2 becomes supercritical about 73-bar and 32ºC. Thus CO2 power cycles inevitably endure supercriticality.

CO2 compression: stranger things?

Energy density of hydrogen lags other fuels?

The Density of Hydrogen is 0.08 kg/m3 at 20ºC and 1-bar of pressure, which is very low, mainly because of H2’s low molar mass of just 2g/mol. Methane, for example, is 8x denser. CO2 is 20x denser. In energy terms, gasoline is 3,000x denser per m3.

Hence hydrogen transportation and storage requires demanding compression or liquefaction. Tanks of a hydrogen vehicle might have a very high pressure of 700-bar, to reach a 40kg/m3 (the same density can be achieved by compressing methane to just 50-bar!). Liquefied hydrogen has a density around 70kg/m3 (LNG is 6x denser).

The density of hydrogen is just 0.08 kg/m3 at 20ºC of temperature and 1-bar of pressure

The energy density of hydrogen, in kWh/m3 also follows from these equations. At 1-bar and 20ºC, methane contains 3x more energy per m3 than hydrogen. Under cryogenic conditions, it contains 2x more energy. Under super-critical and ultra-compressed conditions, it contains 4x more.

The energy density of hydrogen is 50-75% lower than natural gas, even after compression/liquefaction

Data into the energy density of gases?

Similar energy density challenges constrain the use of ammonia as a fuel, as tabulated in the data-file, contrasted with other fuels, and discussed in our research note here.

Combustion fuels: density, ignition temperature and flame speed?

This data-file allows density charts — in kg/m3 and in kWh/m3 — to be calculated for any gas, using the Ideal Gas Laws and the Clausius-Clapeyron equations. The data-file currently includes methane, CO2, nitrogen, ammonia, argon, water and hydrogen.

Density of methane in kg/m3 and kWh/m3

Clausius-Clapeyron: gas liquefaction?

Density of CO2: strange properties?

Super-critical fluids: fourth state of matter?

Energy density of hydrogen lags other fuels?

Data into the energy density of gases?

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