Results of analysis performed in the Norwegian CCS Research Centre (NCCS) indicates that mobility control in CO2 storage can reduce the total cost per tonne of CO2 stored.
The behaviour of CO2 in the storage reservoir
When we compress CO2 and inject it into a reservoir for permanent storage, it becomes a peculiar combination of liquid-like density but gas-like viscosity. The high density means that it requires a relatively small amount of pore space, while the low viscosity means that it has a tendency to shoot past the formation water it is displacing in a process called ‘viscous fingering’.
While the CO2 density is high, it is still lower than that of water, and this causes the CO2 to migrate to the top of the storage reservoir and further amplify the bypassing of the formation water.
Injection of CO2 will increase the formation pressure near the injection well. The pressure will dissipate outwards to the boundaries of the storage site, or towards wells that are used for pressure control through extraction of formation water. Viscous fingering and gravity segregation could cause CO2 to reach these pressure control points early and therefore limit the amount of CO2 that can be safely injected and stored.
Controlling the effective viscosity of CO2
In NCCS we investigate so-called ‘mobility control’ methods for CO2. Mobility control methods increase the effective viscosity of CO2 by adding chemicals to the CO2 that increase the viscosity directly or by adding surfactants that allows the creation of stable foams that slow down the CO2. Both alternatives will make more of the injected CO2 stay close to the injection well and will allow more CO2 to be injected into the storage reservoir before it reaches the pressure control points.
The effect will, of course, depend on how efficient the added chemicals are at creating the necessary viscosity increase. The effect will depend on the concentration of the chemicals. In NCCS we have performed experiments to measure the relation between concentration and effective CO2 viscosity for various surfactants known to stabilise foam between CO2 and formation water.
Read more: The Impact of NCCS Research & Innovations
The right time and place
When we know the necessary surfactant concentration, we further must investigate how to apply the surfactant. Various mechanisms such as dissolution into the existing formation water or adsorption to mineral surfaces work to dilute the concentration of the surfactant once it is in the reservoir, and these must be compensated for, either by injecting at a higher concentration or by identifying chemicals that prefer to remain dissolved in the injected CO2.
The CO2 at the front needs slowing down the most. Injecting surfactant together with the last CO2 will not be very useful. But is it better to inject a high concentration for a short time, or a lower concentration for a longer time? And is it better to inject surfactant together with the CO2 or to place it in the storage reservoir together with some injected water before we start the CO2 injection? These kinds of questions have been addressed in NCCS through reservoir simulations.
The results show that successful application of CO2 foam can more than double the efficiency of CO2 storage. The simulations also indicate that surfactants that can be injected together with the CO2 are more effective at increasing the storage efficiency.
Will it reduce the total cost of CO2 storage?
The use of surfactants of course increases the cost of the storage operation. But if more CO2 can be injected in the same storage reservoir the number of wells needed to store a given amount of CO2 will be reduced. The area that later needs to be monitored is also reduced.
The question is whether these benefits of the increased storage efficiency compensates for the added cost of purchasing and handling the chemicals. Through work in NCCS in 2020 we have addressed these questions with reservoir simulations and a simplified economic analysis. The simulations run assume that a storage reservoir is developed with water extraction wells for pressure control, and that surfactants are used to increase the utilisation of the storage reservoir.
The funding set aside by the Norwegian government for the offshore exploration well for the Northern Lights project indicates a well cost of about NOK 500 million. Cost per well in a project with many wells will probably be lower. The economic model in our work assumes that each well costs USD $20 million. Surfactant cost is assumed to be USD $1 per kg, which is low but not unrealistic for chemicals produced in large quantities.
Results of the analysis indicate that mobility control in CO2 storage can indeed reduce the total cost per tonne of CO2 stored. But the overall cost reduction requires that the surfactant prefers to stay dissolved in the CO2, and that storage efficiency can be significantly increased (by more than 25%).
In projects where the well costs are higher, the cost of developing additional storage sites to inject the additional CO2 would also increase, and this will make mobility control more attractive.
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