Transportation and storage of renewable hydrogen and electrofuels

How is hydrogen transported?

Hydrogen can be transported in many ways that include:

  • As a pressurized gas in truck- or rail-mounted tanks.
  • In lower pressure metal hydride tanks.
  • As a cryogenic liquid in insulated tanks.
  • In pipelines.
  • Combined with other molecules to make other liquids and gases that can generally be less expensively transported (e.g., ammonia, methane, methanol, formic acid, and various hydrocarbons).

Can hydrogen be transported using existing natural gas pipelines?

Yes, but there are various limiting factors. Concentrations above 20% (by volume) may cause some end use appliances to perform differently than designed. Accommodating higher concentrations would require adjustments to end use burner tips. Hydrogen can also cause embrittlement in steel pipelines, so the acceptable level of hydrogen varies depending on the specific pipeline materials in use.

How do pipelines built to carry hydrogen differ from pipelines built to transport other fuels?

The biggest difference is that hydrogen pipelines avoid exposing steel to the hydrogen, instead relying on lined steel pipes or materials such as fiber reinforced polymers.

Are there existing pipelines that have been specifically designed for transporting hydrogen?

There are about 1,600 miles of hydrogen pipelines currently operating in the United States. The largest industrial use of hydrogen is in oil refining and these pipelines are largely serving oil refineries on the Gulf Coast.

How can hydrogen be stored?

There are many options for hydrogen storage:

  • As a gas in pressurized tanks.
  • In lower pressure metal hydride tanks.
  • As a cryogenic liquid in insulated tanks.
  • In pipelines.
  • Combined with other molecules to make other liquids and gases that can generally be less expensively transported (e.g., ammonia, methane, methanol, formic acid, various hydrocarbons).
  • In underground natural gas storage fields.
  • In underground salt caverns.

There are proposals to store renewable hydrogen underground in geological formations similar to those used for storing natural gas. Has this been done successfully and are there technical challenges to storing hydrogen in this way that differ from those encountered when storing natural gas?

Geologic hydrogen storage is not new technology. There are several locations around the world that store hydrogen underground, predominantly in salt caverns, although there are other geologies believed to be suitable for large-scale storage. 


How widespread are geological formulations that are good candidates for use in storing hydrogen?

Access to natural gas storage (e.g. if hydrogen is mixed with natural gas) is widely accessible at very large quantities through the natural gas pipeline system. Geological salt dome formations are available in various locations in the United States, concentrated in the Gulf Coast, sporadically through the Rocky Mountain region and west to as far as Nebraska and Oklahoma, and the large Appalachian deposit centered on Michigan.


What are the efficiencies (i.e., energy losses) associated with energy storage and retrieval using competing hydrogen storage methods?

Although hydrogen has one of the highest energy densities on a mass basis, it has one of the lowest energy densities on a volumetric basis. Consequently, storing large amounts of hydrogen is not so direct as putting it in an unpressurized tank. For example, a ten gallon tank of hydrogen at ambient pressure and temperature holds only as much energy as 2 teaspoons of gasoline.

Hydrogen can be compressed, liquefied, or used as a feedstock to boost its energy density to levels useful for storing significant quantities. Commercially available fuel cell electric vehicles use hydrogen compressed to 700 times atmospheric pressure (700 bar or about 10,000 psi). It takes about 30 gallons of hydrogen at 700 bar (5 kg) to drive a car about 300 miles.

The amount of energy used to compress hydrogen to these high pressures can be from 5-17% of the energy stored in the hydrogen itself depending on the pressure. Liquefying hydrogen can take 30% of the energy in the hydrogen.

Converting hydrogen to methane makes it completely interchangeable with natural gas for transportation and storage. Hydrogen and carbon dioxide combine to form methane in a well-developed “methanation” process. There is a 20% energy loss (as potentially useful waste heat) in that process.

Hydrogen can be used as a feedstock for other carrier chemicals such as ammonia, formic acid, methyl-cyclohexane, et al. These each have their own energy losses, generally in excess of the ones described above.

Volumetric energy density of compressed and liquid hydrogen compared with other common fuels. (Hydrogen Storage Fact Sheet, US DOE Fuel Cell Technologies Office, March 2017)



What are the capital costs associated with competing hydrogen storage methods?

Costs on an energy storage capacity basis ($/kWh) vary widely depending on the storage technology, quantity to be stored and whether it is mobile (e.g., in cars, ships, or aircraft) or stationary applications. For example, the incremental cost of storage at an existing salt dome facility is extremely low­– perhaps on the order of $1/kWh, compared with liquid hydrogen storage on spacecraft. Some stationary pressurized hydrogen storage costs for a range of projects compiled in 2005 is illustrated below.

Capital costs quoted for compressed hydrogen storage facilities, based on a 2005 analysis. Energy units are based on lower heating value of hydrogen. Adapted from Systems Analyses Power to Gas: Deliverable 1, DNV KEMA, June 20 2013, Figure 23, p. 69.

Is any of the energy consumed in moving hydrogen into storage as a compressed gas recoverable when it is taken out of storage?

This is a possibility, especially for high pressure storage. However, a significant loss of energy occurs during compression in the form of heat that would have to be recoverable for efficient recovery of compression energy.

Is any of the energy consumed in turning gaseous hydrogen into liquid hydrogen recoverable when it is taken out of storage, or does that process require an additional energy input—as with liquefied natural gas?

Some of the energy needed to compress or liquefy hydrogen can be recovered, but at additional capital expense.

Can’t the needs for energy storage attendant with use of variable renewable source like wind and solar already be satisfied using lithium-ion battery technology?

Some of the needs for energy storage may best be met with higher efficient battery and other conventional storage technologies (pumped hydro, compressed air, etc.). However, the cost of battery energy storage is orders of magnitude higher than the cost of creating and storing the energy as fuels. Battery storage is more efficient than creating and storing hydrogen and directly contributes new reliable capacity to a power grid, but the cost of battery storage is largely proportional to the quantity of storage capacity. As a result, the costs become prohibitive for storing energy for more than a few hours at a time.

Conversely, most of the cost of creating fuels with electricity are based on cost of the machinery to convert electricity to hydrogen. For example, the cost of one kilowatt-hour of battery storage is targeted to get down to $100. At that point, the cost of storing 2 kilowatt-hours will be $200, 3 Kilowatt-hours will cost $300, etc. Storing large quantities of electricity to absorb or supply power over long periods rapidly becomes prohibitive.

On the other hand today’s installed cost of electrolysis is perhaps $1,500 per kilowatt (not kilowatt-hour). Making one kilowatt-hour of hydrogen would cost about $2,000 (taking account of the efficiency loss), but could be accomplished in one hour. Storing 2 Kilowatt-hours would cost the same, just running the device for an extra hour. This device could produce almost 9,000 kilowatt-hours in a year, which would take nearly $900,000 of batteries (at $100/kWh), 450 times as much as the electrolyzer.

For storing large amounts of electric energy needed for seasonal energy storage, making fuels is hundreds of times less expensive than battery storage, albeit less efficient.

Doesn’t the Pacific Northwest already have all the energy storage it needs in its hydroelectric system?

The Northwest is blessed with comparatively large amounts of energy storage in the form of water in reservoirs behind dams in the Columbia River drainage basin. That storage is leveraged to good purpose today to balance the variability of wind and solar on the system, but also to supply power during periods of extended droughts that may last up to nearly four years. It is the energy storage necessary to provide reliable service from the variable renewable resource that is the Columbia River Power System.

Going further, to store all of the energy needed to bridge extended wind and solar “droughts” when we move to 100% renewable energy systems will be beyond the capability of the hydro system, especially during drought years.

Moreover, the region already experiences times when the production of energy from hydro, wind, and solar exceeds the region’s demand for power and the system’s ability to store it. At those times, the energy is merely turned away—power that has no incremental cost of production is already being wasted for lack of storage and demand. These super-surpluses of low-cost, low-carbon electricity will only increase as we build out the fleet of wind and solar plants on the way to establishing a zero-carbon grid. Creating new markets for electricity can reduce the amount of energy we throw away, and use it to create fuels to displace use of fossil fuels in other parts of the energy economy.

Hydrogen advocates have proposed that we consider using hydrogen pipelines to wheel renewable energy long distances in lieu of high-voltage direct current (HVDC) high-voltage alternating current (HVAC).  Is that idea feasible, and how might such a scheme compare in cost and efficiencies with electrical transmission lines?

The US has about 1,600 miles of hydrogen pipeline today, mostly along the Gulf Coast to service oil refiner hydrogen demand. Low concentrations of hydrogen can be mixed in the existing natural gas pipeline system for transport, and existing gas pipelines may be able to be retrofit to accommodate pure hydrogen. Hydrogen can also be produced near to generation and uses of hydrogen that may not require transportation, and has the potential to reduce congestion on existing transmission system. Long distance pipeline transmission of hydrogen is a definite possibility worth continued study.

See: Hydrogen Pipelines (web page), US DOE Hydrogen and Fuel Cells Technology Office.