Technical considerations for subsurface storage to support the energy transition

Gordon Taylor, Director, Consulting
David Element, Principal Reservoir Engineer

13 Dec 2021

In our previous article The importance of subsurface gas storage as part of the energy transition mix, Gordon Taylor wrote about the need for underground gas storage and its critical role in the energy transition,  to provide energy security when renewable sources aren’t available, and as a store for carbon dioxide (CO2).

Whether the outcome is to permanently store gas with CO2 (following the capture of CO2 from industrial processes) or storage and recovery of natural gas, and hydrogen in the future, the key attribute of a feasible geologic store, or ‘trap’, is its ability to receive the gas efficiently, store it effectively and – for natural gas and hydrogen storage – to recover the gas economically.


Underground gas storage pipes

This article expands on previous insights by providing technical detail on some of the key sub-surface design elements of underground storage of natural gas, CO2 and hydrogen. Finally, some comments are made on compressed air storage and on auditing of storage capacity.

Natural gas storage

Natural gas is taking a larger share of the energy mix as countries reduce their reliance on coal for electricity generation, and it’s easy to see why. Natural gas can be stored underground and delivers nearly twice as much electricity as coal for the same amount of CO2 emissions[1].

The short-term and long-term fluctuations from renewable sources mean they can’t always meet energy demand. Natural gas storage can partly address this and can also be used as a strategic reserve to level out shortages in supply. Based on seasonal variations, gas is injected when demand and price are low, then withdrawn again as needed. Natural gas storage also provides short-term protection against unforeseen supply disruption by providing an immediate and reliable energy source which can quickly be utilised to generate electricity. Natural gas storage allows large natural gas consumers to hedge supply and price risk and, should prices suddenly spike, capture the upside opportunity.

How does natural gas storage work?

A natural gas storage system needs a working gas volume, injection capacity, withdrawal capacity and a volume of cushion gas. The working gas volume is the volume that can be injected and withdrawn during normal operations. The cushion gas volume is the gas that is required to remain in store to maintain reservoir pressure.

The injection and withdrawal capacity, which are largely dependent on the storage pressure, control the rate at which gas can be injected or withdrawn. If storage pressure is low, gas can be injected at high rates but withdrawn at low rates. Conversely, if storage pressure is high due to considerable working gas in store, injection rates will be low, but withdrawal rates will be high. Depending on the type of storage, studies that may be required include pore and regional scale modelling, geomechanics, trap integrity, rock chemistry, core studies and injectivity/productivity.

For depleted gas fields, there is a well-documented hysteresis in the field’s ability to be repeatedly repressurised and depleted, which must also be modelled.

Where is natural gas stored?

The most common types of natural gas storage are in depleted gas reservoirs and salt caverns and, to a lesser extent, in aquifers. Aquifers and depleted aquifers have a much more useful storage capacity for the long-term capture and storage of CO2.

Depleted fields: The advantage of depleted gas reservoirs over other types of gas storage is that any unproduced gas can be used as cushion gas, and the fields may also have very large working gas capacity. Depleted reservoirs are also likely to be linked to existing gas infrastructure, which reduces the upfront investment needed.

Salt caverns: Salt caverns are located in thick halite formations. They are made by pumping fresh water down a borehole into the salt layer to dissolve the salt, then circulating the resulting brine to the surface. This process continues until the required size of cavern is reached.

Depleted aquifers: Converting an aquifer to a natural gas reservoir requires long, slow injection cycles to displace the water. Depleted aquifers have the largest potential storage capacity compared to other options. However, they are less likely to have the wealth of subsurface technical data available for depleted oil or gas fields.


CO2 storage

Atmospheric CO2 is widely accepted to be a major contributor to global climate change. Carbon Capture and Storage (CCS) refers to the process of capturing CO2, compressing it, transporting it to a storage site, and injecting the fluid into the site for long-term sequestration.

Although various methods of storage have been proposed, geological storage, where CO2 is permanently stored deep underground, has been studied for decades and is well understood.

Globally, 300 million metric tonnes of CO2 have been safely captured and stored over the past four decades. CCS is expected to play a very significant role in meeting the global emission targets set out in the Paris Accord. Indeed, most of the accepted forecasts of global energy requirements agree that without CCS it will be impossible to limit global warming to 1.5°C by 2050.

How does CO2 storage work?

The injection of CO2 into deep geological formations utilises technologies and modelling capabilities that have been developed by the oil and gas industry over many years.

When CO2 is injected (via a well) into a geologic storage site, the gas flows through the porous media. The storage sites are typically at depths greater than ~1 km. CO2 will be supercritical at these depths, meaning that the fluid has a liquid-like density (which is favourable for storing large quantities), but a gas-like viscosity (which is favourable for injecting the CO2). The CO2 needs to be compressed at surface level before it is injected into the reservoir.

The nature and the type of the trapping mechanisms for reliable and effective CO2 storage vary within and across the life of a sequestration site depending on geological conditions. CO2 trapping is well understood thanks to decades of experience in injecting CO2 for enhanced oil recovery (EOR) and for dedicated storage.

Monitoring of CO2 storage sites, during and after injection, is another key aspect and may be necessary for a significant period (possibly up to 50 years). This involves a range of techniques, including atmospheric, surface and subsurface monitoring at the storage site, aimed at robustly demonstrating there are no fugitive CO2 emissions from the site.

Where is CO2 stored?

Geological storage of CO2 involves the injection of captured CO2 into a deep underground geological reservoir of porous rock. As with natural gas storage, there are several types of reservoir suitable for CO2 storage, notably depleted oil and gas reservoirs, or deep aquifer formations (saline aquifers).

Depleted oil and gas reservoirs are porous rock formations that have trapped crude oil or gas over geological time periods before being developed. Such depleted reservoirs are likely to have been characterised and modelled in detail during the planning and operational phases of hydrocarbon production.

Deep saline formations are layers of porous and permeable rocks saturated with brine, which are widespread in both onshore and offshore sedimentary basins. Saline aquifer storage provides a significantly higher storage potential than depleted reservoirs.


Related read: Carbon capture and storage solutions at RPS

Hydrogen storage

Hydrogen will play an important role in the world’s future energy systems, and the need for hydrogen storage will grow as renewable energy generation increases. There are potentially many ways that hydrogen could be stored: in liquid or gaseous state in surface tanks through to underground storage in a gaseous state. 

Large scale, commercial underground hydrogen storage has been demonstrated in salt caverns in a handful of projects in the USA and in Europe. The storage facility at Teesside, UK, has been in operation since the 1970s. Salt cavern storage facilities have relatively small storage volumes. In addition, several possible projects are currently being evaluated in Europe. Large scale hydrogen storage, however, would require the use of depleted hydrocarbon fields.

Despite the capacity limitations, salt caverns represent a favourable option for hydrogen storage for the same reasons as for natural gas storage (extremely low permeability of halite, low construction costs, and small surface footprint). Additionally, hydrogen is unlikely to react with the halite. As with natural gas storage, cushion gas is required to maintain minimum pressures. The creation of man-made caverns also creates a sump of debris, which reduces storage volume, at the base of the cavern.

To our knowledge the only field tests of hydrogen storage in porous rocks have been in Argentina, and at low pressure in depleted reservoirs in Austria. As hydrogen is not found in its free state in oil or gas reservoirs, there have been concerns regarding whether a depleted field could store hydrogen. The hydrogen molecule is smaller, more mobile and has greater fugacity than hydrocarbons, nitrogen or CO2 molecules, so there is concern whether it could be trapped. Additionally, there is concern over biological and chemical reactions between the sealing and reservoir rocks, the cushion gas and other fluids in the reservoir and concern over potential microbial growth.

Considerable research is ongoing and, although in early stages, there appear to be no fundamental issues to prevent hydrogen storage in porous media.


Related read: Alternative fuels: Hydrogen

Compressed air storage

There is increasing interest in a storage technology that was developed well over 50 years ago: Compressed Air Energy Storage (CAES). CAES is based around a gas turbine cycle. Surplus power is used to compress air using a rotary compressor and then store it, often underground. When power is required, it is released from the chamber and passed through an air turbine that generates electricity from the flow of the high-pressure air. The output can be boosted by burning natural gas in the high-pressure air before it enters the air turbine (as in a conventional gas turbine), albeit with accompanying CO2 emissions. Compared with other energy storage technologies, CAES plants would have a very large power rating and storage capacity, low self-discharge, and a long lifetime. However, conventional CAES plants have a relatively low round trip efficiency.

As with natural gas storage, a large proportion of the gas injected in a CAES system is used as a cushion.

Although proven technology, only two commercial CAES plants have ever been built. The first CAES plant was at Huntorf, Germany (built in 1978) and is still in operation. There is a second CAES facility in McIntosh, Alabama, USA, with a total storage capacity of 400 MW. Both facilities store compressed air in salt caverns.


Assessing an E&P company’s oil and gas Reserves and Resources volumes is a key part of any E&P company’s internal governance process. Independent auditing of Reserves and Resources is essential for raising finance for oil and gas developments or when listing the company on a stock market. The most widely used standard for assessing oil and gas volumes is the 2018 Petroleum Resource Management System (PRMS), which was based on a system developed by the Society of Petroleum Engineers (SPE) in the 1960s and which has been modified by the SPE in conjunction with other professional institutions since then. The SPE has developed a similar system for auditing underground storage capacity called the “CO2 Storage Resources Management System (2017)”. Although specifically prepared for CO2 storage, the principles can be applied to storage of any gas.


If you would like any additional information on these various storage solutions and how RPS can support your goals, please contact either Gordon Taylor at, or David Element at

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