It’s useful to get an idea of the relative size of markets for commodities of interest and their products (and byproducts).
What’s hot now and likely to remain hot for the foreseeable future is hydrogen.
According to data provided by RBAC’s G2M2® Global Gas Team, the International Energy Agency (IEA) has estimated global demand for “pure” hydrogen in 2018 to have been about 73 million tons. Demand for hydrogen mixed with other gases was about 42 million tons. So together we could estimate the market in 2018 to have been about 115 million tons.
According to BP Statistical Review of World Energy, global consumption of natural gas in 2018 was about 3,849 billion cubic meters (BCM).
To put this in perspective, we need to use the same units of measure. BP uses 1.36 BCM per million tons as their conversion factor for natural gas.
3,849 BCM of natural gas at standard temperature and pressure has a mass of about 3,849/1.36 = 2,830 million metric tons.
Thus the relative market size for natural gas in 2018 was 2,830 / 115 which is about 25 times that of hydrogen – in metric tons.
But let’s do the calculation in cubic meters. Note that natural gas is mostly methane with a little bit of other light hydrocarbons like ethane. For our purposes, we can consider it to be methane. By molecular weight, methane is 16.04/2.016 = 7.956 times as heavy and therefore as dense as hydrogen (at the same temperature and pressure). That is, hydrogen takes up about eight times as much volume as methane for the same amount of mass.
So, for hydrogen, 1 million tons has a volume of 1.36 x 7.956 = 10.82 BCM at standard temperature and pressure. And 115 million tons would have a volume of 115 x 10.82 = 1,244 BCM. In summary, the market for methane (natural gas) is about 4,000 BCM and that of hydrogen is about 1,200 BCM so by volume the hydrogen market is about 30% of the natural gas market.
According to what we’ve been reading in the press, hydrogen can be mixed with natural gas in pipelines and in storage facilities but only up to about 15 to 20%. Sometimes we read up to about 30%. Hydrogen is currently supplied primarily from sources nearby where it is used. In the US there are some short-haul pure hydrogen pipelines, mostly in the Gulf Coast region for use in refineries. But if hydrogen were produced from natural gas in upstream producing areas and then mixed with natural gas in pipelines, we might be able to accommodate almost a doubling of hydrogen production with the existing natural gas delivery system.
But doubling the amount of hydrogen produced, doesn’t mean doubling the amount of hydrogen delivered. Pipeline compression uses about 4 to 5 times as much hydrogen as it does natural gas. So, if today’s natural gas pipeline fuel use is about 4% to 5% of total production, it could be 16% to 25% for hydrogen.
Another vital factor is the energy content in each of the gases. According to research reports, on a volumetric basis, hydrogen carries only about 31.4% of the energy potential of methane. On a weight or mass basis, hydrogen is more energetic, but recall that it is about 1/8 as dense as methane.
Assuming a mix of 80% methane and 20% hydrogen, the amount of energy actually delivered is going to be about 0.8 x 1 + 0.2 x 0.314 = 0.8628 or 86% of that of pure methane. In addition, as mentioned above, the amount of fuel consumption in compressors is higher for hydrogen. So, for the same volume of gas deliveries in cubic feet or cubic meters, one will get only 85% of the energy as for pure methane. The more hydrogen you put into the gas stream, the more volume you will have to ship to get the same amount of delivered energy.
In the end, what do we gain by investing in a mixed methane-hydrogen market? Basic thermodynamic principles tell us you always lose energy when you convert one form of it to another. So, making hydrogen from methane using a standard reforming process, then mixing it with other methane and transporting it to markets where the mix will be burned for space or process heat is going to cost substantial amounts of energy which cannot be usefully recovered. The only potential benefit to this kind of setup would be if the CO2 produced in creating the hydrogen from natural gas is captured and used or stored rather than emitted into the atmosphere. This would convert such hydrogen from “gray” (no carbon capture or use) to “blue”.
If the plants making such blue hydrogen are located near oil producing formations producing associated gas, the carbon dioxide can be used for enhanced oil recovery. It might also be delivered for storage into depleted oil or gas fields in the area. Alternatively, the hydrogen might be produced using solar or wind-generated electricity through the process of electrolysis. The solar and wind potential is high in many existing gas producing areas where pipelines have already been built. Good production sites for such “green hydrogen” might be where gas production has declined but the pipelines are still available to take a methane-hydrogen mix to market.
A third possibility is making hydrogen from methane using pyrolysis. This procedure produces hydrogen and solid carbon, rather than carbon dioxide. The benefit is low or zero emissions, obviously, but the amount of carbon produced would overwhelm today’s markets for such products. While these calculations are approximate, based on what’s known and possible today, they do point out some of the potential and challenges for a gas market based on methane-hydrogen mixes as one way forward to a lower carbon future.
RBAC’s G2M2® Global Gas Market Modeling System™ provides robust modeling capabilities well-suited for simulating changes in market conditions including the challenges facing green gas solutions. Analysts have wide-ranging flexibility in modeling supply, demand and infrastructure scenarios to help them assess market risk and opportunities, thus leading to better informed and more optimal decisions.
