The what and when of P2G

'P2G' stands for 'power to gas'.  I've talked about this before.

It goes like this.  Hydrogen blended with pure CO₂ over a catalyst, at pressure, combines to produce methane.  If you produce the hydrogen using renewable electricity, then this process is carbon-neutral.  The CO₂ produced when the gas is burnt is the same CO₂ which was taken up from the atmosphere when the synthetic methane was made.  The problem is this.  Because the chemical bonds between hydrogen and oxygen are so strong (that's why hydrogen burns so easily) it takes a lot of energy to break water apart during electrolysis.  The round-trip efficiency of power to gas is 50% or less, compared with 90% for li-ion batteries.  Obviously, we would prefer to use batteries.  But at high latitudes, we will need at least 2 weeks of storage.   High latitudes have not much solar in winter, when demand is highest, and although winds are stronger in winter, there can be several successive days of low winds.   The longest no-wind period in Denmark is 7 days.  Using li-ion batteries to cover 2 weeks of storage would be very expensive.  So that's where P2G comes in.  When there is surplus power in the grid (summer/strong and persistent winds) we produce hydrogen/methane and store in in the existing gas grid/gas storage and when we need electricity we burn the gas we've made in legacy gas plants.

Source: ResearchGate

Often touted as the missing link in the energy transition, power-to-gas (P2G) has not yet had its time to shine. While the technology has been around for decades, large-scale projects have been exceptionally rare. Over the last year, however, encouraging signals are emerging as research, pilot projects, and small-scale applications appear to have picked up pace. As debate continues about the tipping point for P2G in terms of conversion efficiency and costs, some market players are optimistic about near-term prospects.

It is certainly an attractive scenario for acceleration of the energy transition. As renewables do their bit in reducing carbon emissions from the electricity sector, synthetic gases – hydrogen and methane – open up a further possibility for greening the gas network. They can also be used to store excess solar and wind energy over long periods of time and to address seasonal intermittency challenges in the grid after being converted back into electricity.

Hydrogen and methane from green electricity sources can also play a role in sector coupling, be it for heating, transport, or industry. So-called ‘syngases’ can also be produced from fossil fuels and biomass. Power-to-gas (P2G) refers to the use of renewable electricity to produce these gases through electrolysis and methanation. But there is a downside: During these processes a lot of energy is lost.

Average efficiencies of electrolyzers, which use renewable electricity to break water down into H2 and oxygen, exceed 70%, and this conversion efficiency can be assumed for on-site use and direct feed-in to the gas network. If the gas needs to be stored and transported, compression or cooling of hydrogen brings losses which can go up to 35%. If hydrogen is reconverted into electricity through fuel cells, the overall process efficiency ends at 30-35%, with significant amounts of energy lost as heat.

Additional synthesis processes can be used to convert hydrogen gas into methane. While the advantage of the process is that the final product is the gaseous energy source which is already the main component of conventional natural gas and can therefore be freely injected into the gas grid, additional energy loss of around 8% is inevitable.

There are different assumptions about the point at which P2G will go mainstream and become cost competitive. An international team of economists from Germany’s Technical University of Munich, the University of Mannheim, and Stanford University in the United States says Germany and the U.S. state of Texas could already host small wind-powered P2G projects that could compete in cost terms with conventional power sources, while large-scale should be viable by 2030.

Another report commissioned by the European Climate Foundation suggests a fossil fuel-free energy system in Europe by 2050 should largely rely on smart electrification and energy efficiency, which could turn out 36% cheaper than green hydrogen at scale, but still considers hydrogen viable where it adds the highest value, such as with seasonal storage and peak power supply. And yet another study for the Hydrogen Council (2017) envisages that by 2050, 18% of global final energy demand could be met by hydrogen, equal to about 78 exajoules (EJ), while the economic assessment by the International Renewable Energy Agency (2018) estimates hydrogen’s economic potential at about 8 EJ globally by 2050 in addition to feedstock uses. While the Hydrogen Council roadmap is the industry’s consensus vision of hydrogen’s potential in the economy under the right circumstances, it is just one vision of numerous potential outcomes; IRENA’s assessment looks at the mix of options to achieve targets set out in the Paris Agreement, ranking options by their substitution cost.

Oslo-based energy advisory firm DNV GL forecasts demand for hydrogen in the energy sector to rise from about 1,000 metric tons today to 39-161 million metric tons per annum in 2050, under various scenarios. Its most recent study into green hydrogen concludes that production of hydrogen from electrolyzers will become competitive with production from natural gas by 2035. “Our research shows there is a competitive position for green hydrogen,” says Theo Bosma, Program Director Power and Renewables at DNV GL. Clearly, competitiveness is directly dependent on the composition of the power system, that is high penetration of solar and wind that causes frequent oversupply. “We analyzed developments up to 2050, and saw there can sometimes be even 3,000 hours of oversupply, so it means it’s absolutely competitive. But, it will be already [the case] in 2035 that it will start to make sense to produce hydrogen through electrolysis, with a sufficient number of hours of low electricity prices compared to steam methane reforming, where you obviously need to pay the penalty for the CO2 emissions,” Bosma says – noting that in the end, it’s all about the cost of electricity.

[Read more here]

The shape of the grid in 2050 seems reasonably clear (unless we discover workable nuclear fusion by then):

• The grid will be powered by a mixture of wind and solar, with more solar in low latitudes and more wind in high.
• HV electricity power lines will connect geographically distinct regions with different climates to provide a more stable output. For example,  the wind in north Texas has a low correlation with the wind in south Texas.  The combined output from both regions is less variable than output from either.
• There will be more renewables capacity than we need, just as there is now with conventional power generation.  That will mean that there will often be surplus generation, which will either have to be curtailed, or stored for later.
• Battery storage will cover 24 hours of usage.  When the batteries are full, the surplus electricity will be stored as gas, both hydrogen and methane. 
• Legacy gas plants and the gas grid will be the backup for when there are prolonged periods where neither wind nor solar power is available.
• The economics of P2G depend upon surplus electricity.  But we won't be producing that in large quantities until the grid is 80% or more renewable.  But when we get there, we will need P2G.  So we must start planning now, and start building out the P2G infrastructure we will need, which may require subsidies.