| dc.description.abstract | Large-scale hydrogen storage can help alleviate the main drawbacks of renewable energy
generation, their intermittency, and their seasonal and geographical constraints. Renewable
energy without energy storage is unable to satisfy the whole system’s energy demand.
Excess renewable energy can be converted to hydrogen through electrolysis (“green
hydrogen”) and stored to be used during periods of high energy demand. Even hydrogen
generated from hydrocarbons, in combination with Carbon Capture and Storage, (“blue
hydrogen”) can help to reduce emissions in the energy sector while transitioning towards a
low-carbon industry. Expectations for energy storage are high but large-scale underground
hydrogen storage in porous media (UHSP) have not been deeply understood. To facilitate
hydrogen supply on the scales required for a zero-carbon future, geological storage in
porous media, such as saline aquifers and depleted hydrocarbon reservoirs can be a valuable
option.
Despite the vast opportunity provided by UHSP, the maturity is considered low, and as such
UHSP is associated with several uncertainties and challenges. Some of them are the
selection of the most suitable cushion gas for maintaining sufficient operational pressure,
the rate of injectivity, different physical and chemical properties compared to other
geologically stored fluids, and the possible reaction of hydrogen with subsurface minerals
and fluids affecting the storage options.
In this project, attempts are made to have a deeper look into the surface and downhole
parameters that must be considered for the safe storage of H2 in geological porous media
and transfer the knowledge or lesson learned from the CO2 storage sites. Comparing and
identifying the element of the storage risks, a general scheme for a safe hydrogen injection
and reproduction in geological porous media will be proposed and certain recommendations
will be made.
The hydrogen storage was created in the synthetically created infinite-acting aquifer using
CMG-GEM software to run the simulation and WINPROP-CMG to model the fluid
parameters. The hydrogen was injected in the middle of the aquifer with residual brine in
the porous medium. The options with three different water salinity levels and various
storage scenarios including multiple operations cycles in the presence of prior cushion gas
injection and methanation reaction were considered and the efficiency of hydrogen storage
was evaluated.
In a case of five cycles of injection and production with the interval of 12 months led to
decreased water production rate over time in the absences of a cushion gas and brine
salinity. As a cushion gas, the nitrogen and carbon dioxide were chosen to be tested. It can
be beneficial to inject nitrogen during various cycles in order to reduce the water production
rate but may not be the best choice if brine salinity rises. Carbon dioxide was injected to
initiate the methanation reaction which occurs after the following hydrogen injection to
yield methane.
Injection of CO2 proved to be the most effective way to remove water from the wellbore
region. However, due to high costs associated with assembling the installation system for
transporting liquid CO2, the first few extraction cycles may be problematic for CO2
injection. In the best scenario, less saline aquifers with cyclic hydrogen injection and
production with CO2 cushion gas were found to be the most efficient. | |