Numerical Assessment of Hydrogen and Gas Mixture Storage in Salt Caverns

With the UK recently doubling its hydrogen production goals to adjust to the market demand the necessity for storage is becoming realised [1]. There are several options for utility-scale storage including salt caverns, deep saline aquifers and depleted gas fields. Salt caverns hold the unique benefit over porous storage of being capable of numerous cycles due to the dynamics of gas withdrawal, making them indispensable in the hydrogen storage strategy of each country. This is exemplified in the UK where it is anticipated to range up to 56TWh. Unfortunately, these are not as readily available as porous storage and hence, competition between different energy storage types may cause problems.

Of the subsurface energy storage systems, natural gas has been in operation for decades and is an established technology with numerous papers investigating different aspects of its operation and development. However, with the ambition of phasing out fossil fuel energy sources compressed air energy storage (CAES) and hydrogen storage are considered in Salt Caverns. It is also understood that during the transitionary period a gas blend may be utilised for the heating, currently, the maximum this stands at is 80:20 %vol of CH₄ to H₂. In most instances (at least for the UK), these systems will compete for storage as offshore wind farms, gas reservoirs and the national transmission system (gas grid) align [2]. Due to the different thermodynamic properties of each gas, it is important to know the impact of cyclic loading of each system on both the gas temperature and how this translates to its surrounding rock.

To investigate this, an idealised model of the NK1 cavern at the Huntorf CAES facility is developed and a historical operational cycle is simulated. Methane, Hydrogen and a Gas blend (80:20 %vol of CH₄:H₂) will be simulated and compared to that of the compressed air energy storage in[3]. This is then furthered by creating a mass-balanced cycle based on the initial cycle and extended for one month to see how these variations develop. The significance of this is to provide insight for the decision-making in which energy storage facility is appropriate for the region as a result of the numerical modelling.

 

References

• Hydrogen Strategy update to the market: July 2022, E.I.S. Department for Business, Editor. 2022: London, United Kingdom.
• Wallace, R.L., Z.S. Cai, H.X. Zhang, K.N. Zhang, and C.B. Guo, Utility-scale subsurface hydrogen storage: UK perspectives and technology. International Journal of Hydrogen Energy, 2021. 46(49): p. 25137-25159.
• Guo, C.B., L.H. Pan, K.N. Zhang, C.M. Oldenburg, C. Li, and Y. Li, Comparison of compressed air energy storage process in aquifers and caverns based on the Huntorf CAES plant. Applied Energy, 2016. 181: p. 342-356.