Sandia study finds underground geologic storage of hydrogen could boost transportation, energy security
09 December 2014
Underground large-scale geologic storage of hydrogen for transportation fuel and grid-scale energy applications could offer substantial storage cost reductions as well as buffer capacity to meet possible disruptions in supply or changing seasonal demands, according to a recent Sandia National Laboratories study sponsored by the Department of Energy’s Fuel Cell Technologies Office.
Geologic storage of hydrogen gas could make it economically possible to produce and distribute large quantities of hydrogen fuel for a growing fuel cell electric vehicle market. The main findings of the economic analysis, published in the International Journal of Hydrogen Energy, show that geologic limitations rather than city demand cause a larger disparity between costs from one city to the next.
The study, said Sandia’s Anna Snider Lord, the principal investigator, could provide a roadmap for further research and demonstration activities, such as an examination of environmental issues and geologic formations in major metropolitan areas that can hold gas. Researchers could then determine whether hydrogen gas mixes with residual gas or oil, reacts with minerals in the surrounding rock or poses any environmental concerns.
Should the market demands for hydrogen fuel increase with the introduction of fuel cell electric vehicles, the US will need to produce and store large amounts of cost-effective hydrogen from domestic energy sources, such as natural gas, solar and wind, said Daniel Dedrick, Sandia hydrogen program manager.
As automakers move ahead with plans to develop and sell or lease hydrogen fuel cell electric vehicles, practical storage of hydrogen fuel at large scale is necessary to enable widespread hydrogen-powered transportation infrastructure. Such storage options, Dedrick said, are needed to realize the full potential of hydrogen for transportation.
Additionally, installation of electrolyzer systems on electrical grids for power-to-gas applications, which integrate renewable energy, grid services and energy storage will require large-capacity, cost-effective hydrogen storage.
Storage above ground requires tanks, which cost three to five times more than geologic storage, Lord said. In addition to cost savings, underground storage of hydrogen gas offers advantages in volume. The massive quantities of hydrogen that are stored in geologic features can subsequently be distributed as a high-pressure gas or liquid to supply hydrogen fuel markets.
While geologic storage may prove to be a viable option, several issues need to be explored, said Lord, including permeability of various geologic formations.
Lord and her colleagues analyzed and reworked the geologic storage module of Argonne National Laboratory’s Hydrogen Delivery Scenario Analysis Model. To help refine the model, Lord studied storing hydrogen in salt caverns to meet peak summer driving demand for four cities: Los Angeles, Houston, Pittsburgh and Detroit.
She determined that 10% above the average daily demand for 120 days should be stored. She then modeled how much hydrogen each city would need if hydrogen met 10, 25 and 100 percent of its driving fuel needs.
Los Angeles has three times the population of Detroit and more than six and a half times the population of Pittsburgh, but the nearest salt formations are in Arizona, so Lord included the cost of getting the stored hydrogen from Arizona to Los Angeles.
Even so, Los Angeles’ modeled costs are significantly less than those for Detroit and Pittsburgh. Salt formations in Arizona are thicker than those for Detroit and Pittsburgh, with larger and fewer caverns. Houston has the best conditions of the four cities because the Gulf Coast offers large, deep salt formations.
To examine the cost of geologic hydrogen storage, Lord started by selecting geologic formations that currently store natural gas. Working with Sandia economist Peter Kobos, Lord analyzed costs to store hydrogen gas in depleted oil and gas reservoirs, aquifers, salt caverns and hard rock caverns.
Other fuels are already stored geologically. Oil from the Strategic Petroleum Reserve, for example, is held in large man-made caverns along the Gulf Coast. Natural gas is stored in more than 400 geologic sites to meet winter heating demands.
Lord envisions that excess hydrogen produced throughout the year could be brought to geologic storage sites and then piped to cities during the summer, when the demand for driving fuels peaks.
Although depleted oil and gas reservoirs and aquifers initially seem the most economically attractive options, hydrogen gas is a challenging substance to store as it is a smaller molecule than methane. Depleted oil and gas reservoirs and aquifers could leak hydrogen, and cycling—filling a storage site, pulling hydrogen out for use and refilling the site—can’t be done more than once or twice a year to preserve the integrity of the rock formation, Lord said.
Salt caverns or hard rock caverns have no permeability issues. Hard rock caverns are relatively unproven; only one site holds natural gas. But salt caverns, which are created 1,000 to 6,000 feet below ground by drilling wells in salt formations, pumping in undersaturated water to dissolve the salt, then pumping out the resulting brine, are used more extensively and already store hydrogen on a limited scale, Lord said.
Lord said her work could lead to demonstration projects to further cement the viability of underground hydrogen storage. Salt caverns are the logical choice for a pilot project due to their proven ability to hold hydrogen, she said. Environmental concerns such as contamination could also be further analyzed.
However, salt formations are limited. None exist in the Pacific Northwest, much of the East Coast and much of the South, except for the Gulf Coast area. Other options are needed for development of a nationwide hydrogen storage system.
Lord’s work adds to Sandia’s capabilities and decades of experience in hydrogen and fuel cells systems. Sandia leads a number of other hydrogen research efforts, including the Hydrogen Fueling Infrastructure Research and Station Technology (H2FIRST) project co-led by the National Renewable Energy Laboratory (NREL), a maritime fuel cell demonstration, a development project focused on hydrogen-powered forklifts and a recent study of how many California gas stations can safely store and dispense hydrogen.
Anna S. Lord, Peter H. Kobos, David J. Borns (2014) “Geologic storage of hydrogen: Scaling up to meet city transportation demands,” International Journal of Hydrogen Energy, Volume 39, Issue 28, Pages 15570-15582 doi: 10.1016/j.ijhydene.2014.07.121
Massive hydrogen storage could also be done in depleted gas and oil fields. However, it has the same problem with geologic limitations as salt caverns. An alternative is to store liquid hydrogen in manmade cryogenic tanks buried underground. That would also be more expensive but they could be build everywhere.
The energy storage question is important to investigate because a solution for the intermittency of solar and wind power needs to be developed before the world can to go 100% renewable and pollution free.
As a temporary solution backup power for solar and wind can be delivered with existing gas and coal powered plants. However, coal power plants that are operated as backup power facilities are difficult to operate profitable. It is impossible for new coal power plants to be operated that way because of their low capacity factor below 30%. Old coal power plants with no debt remaining still make economic sense. However, eventually fossil based backup power must also be phased out. One promising method that emerges as a fully scalable solution for long-term (even seasonal) renewable energy storage is to use heat sinks. Siemens wind power is now in the early stages of developing a new idea based on storing heat up to 600 degrees Celsius in large reservoirs of sand or stone that is buried underground and insulated to prevent heat losses. Just one facility 3 to 4 square kilometers large and 10 meters deep can store enough heat to power steam turbines that could make all the electricity that Denmark typically consumes in 10 days. That would solve the intermittency problem completely for a country like Denmark that strive to go 100% fossil free using wind power.
In Siemens solution heat is transferred into the heat sink using heat pumps (compressors) compressing ambient air at 1 bar and 20 degrees Celsius to 30 bars and 600 Celsius and blown through standard steel tubes within the heat sink. After delivering some of the heat to the heat sink the air is decompressed through a gas turbine that helps turn the compressor. That process also produces freezing cold air at minus 100 degrees as the exhaust of the gas turbine to be used for cooling (say industrial food storage).
Siemens early estimates is that they can make electricity at about 12 cents per kwh using such a facility which is lower than all the alternative methods including compressed air, hydrogen or pumped hydro storage. As mentioned these alternative methods also require suited geographic locations like a depleted gas field for storing compressed air or hydrogen or a steep mountain for hydro storage. The heat sinks can be build anywhere and at any size. Potentially even a house owner with solar panels on the roof and heat sinks buried in the garden could do this but the cost would go up in such a small scale facility. Mass production could of cause bring it down for such micro facilities.
Danish source for Siemens project
Posted by: Account Deleted | 09 December 2014 at 07:36 AM
Ridiculous. I stop reading this article half way, it look it was written by a 16 y.old student. Hydrogen should be done at the car hydrogen station and store there. The smallest the machinery the better. On the long run if hydrogen take off then the capacity should increase. Transport the green electricity to the hydrogen station, electrolyse water then store it in the tank. When the tank is full then stop the electrolizer. Green electricity can be store in bevs that are connected by smart chargers, electrolyze water at hydrogen station and if there is surplus than transformed in synthetic gasoline.
Posted by: gorr | 09 December 2014 at 07:51 AM
Store the CO2 from fossil fuel power plants then create a pipeline network to get it to points of use. At those points the CO2 is combined with hydrogen to make methane and methanol.
Posted by: SJC | 09 December 2014 at 08:15 AM
Better yet, combust coal underground, utilizing much geothermal heat to create the syngas. Better than 50% yield of H2 v. methane and CO has been reported.
There is inexplicable reluctance to carry syngas or CO in dedicated gas grid lines. Diffusion in storage tanks or caverns will separate out the hydrogen in quantities needed.
Now about rocks as heat sinks. I recall a city in Sweden was fitted to pump steam into granite for the purpose. The Palisades of NJ could have served this purpose for Jersey City, which has seen much high rise development. Instead of building a new city gas system in the last several years, steam lines could have been built instead, using CHP from nearby gas turbines. Since additional gas service was built connecting PA to NYC, some finance for my proposal could have been gotten by not building the trunkline at all.
Posted by: kalendjay | 10 December 2014 at 05:24 PM