The Task focus ois to maximise the value of investments and operation cost for a geologic CO2 storage site. CO2 injection into water-flooded oil reservoirs (CO2-EOR) is an efficient method for increased oil production. This can create a positive business case for CCS while safely storing large amounts of CO2. Improved methods for optimisation of storage capacity are needed to make the step from demonstration to large-scale deployment of CO2 aquifer storage.

CO2 enhanced oil recovery, or CO2-EOR, is the process of injecting CO2 into oil reservoirs to mobilise some of the remaining oil. CO2-EOR has thus far been the only large-scale use of COwhere CO2 has a positive economic value. Several studies have shown that large-scale CO2-EOR in the North Sea can be profitable for oil prices down to 50 USD/bbl. Industry relevance is therefore evident.

The activity on CO2-EOR in NCCS is mainly relevant for Deployment Case 2 (Link). In this scenario an infrastructure transporting CO2 from European sources to the North Sea is in place and sufficiently large amounts of CO2 are readily available for use in EOR operations. However, CO2-EOR may also be relevant for an extended phase of the first deployment case (DC1), where the amount of captured CO2 is increased beyond 1.25 Mt/year.

The net cost of the overall CCS chain is the main deployment barrier addressed. This barrier can be reduced or overcome by providing value through production of additional oil.

Reservoir management
Optimal use of a storage site is an important issue since it will increase the amount of CO2 stored for the necessary investments in site development. This means that the total cost per tonne of CO2 stored will be reduced, which will make CCS more attractive as an emission reduction option and increase the likelihood of the deployment of large-scale CCS. The first few CO2 injection operations will likely focus on demonstration of feasibility and safety. However, active management and optimisation of the available storage capacity will become important when the injection rate increases beyond a few Mt/year for a single storage site. Good reservoir management will be imperative in efforts to minimize storage-related costs.

Results 2020

Work in Task 11 in 2020 has led to the submission of three journal manuscripts.

Laboratory testing of commercial surfactants for CO2-brine foam stabilisation has demonstrated significant differences between the surfactant systems in the way the surfactant concentration influences the foam strength. Loss of strength as the concentration is reduced can be gradual or it can be sudden as the concentration falls below a given threshold. This concentration dependence of foam strength is important for the performance of CO2 mobility control in field application and should therefore be investigated further to provide guidance on the most promising surfactants.

Earlier work in Task 11 has demonstrated that CO2 mobility control, if successfully applied at field scale, can give significantly increased storage efficiency (the fraction of pore space that is occupied by stored CO2). This year, we have extended this work with an economic analysis. The economic model includes cost of surfactant purchase and handling, which could be a significant fraction of the total expenses for the storage operation. The benefit of increased storage efficiency could still outweigh the increased costs and give a reduced total cost per tonne of CO2 stored. Our work shows that this is most likely to occur if the surfactant can be dissolved in the injected CO2 and if the surfactant preferentially dissolved in the CO2 over the formation brine. In the most beneficial cases the saving in storage cost is more than 1 € per tonne of CO2 injected.

While CCS chains in the current pilot and demonstration phases are mostly connecting a single source to a single sink, CCS chains in the later large-scale deployment phases (DC 2030 and DC 2050) could also connect several CO2 capture facilities to larger transport and storage networks. The transport and storage networks must be developed in such a way that CO2 supplied by the capture facilities always can be received and stored. The network design has to account for any geological uncertainty remaining after the storage site characterisation and development phases.

In the third manuscript we describe a probabilistic tool for studies of such networks, and apply it to a synthetic case for a CO2 storage hub development on the Norwegian Continental Shelf. The paper also discusses how possible designs for a pipeline network supplying CO2 to the storage hub can have different response curves to a random injection well failure. This emphasises the need for flexibility both in the internal transport pipelines in the storage hub and in the injection system.

Generic illustration of a transport and storage network for a CO2 storage hub with several sites
Generic illustration of a transport and storage network for a CO2 storage hub with several sites

Main results 2019

The NCCS CO2-brine foam module for the MATLAB Reservoir Simulation Toolbox (MRST) has been used to simulate core flooding experiments with different foam-generating surfactants. The results are compared to actual experiments performed with commercially available surfactants. This is valuable information when screening for surfactant properties that will be most beneficial for field application.

Use of foam is a promising method for mobility control of CO2 in saline aquifer storage. Simulations at field scale indicate that storage capacity can be more than doubled if CO2 mobility control can be successfully applied in the early phases of the injection operation.

Further delimitation of the scope of a tool for optimisation of storage site portfolios has been discussed with industry partners in workshops. The goal is to aid in the decision-making for the development of CO2 transport and storage network through the creation of a tool that calculates the incremental cost of reducing the risk of not being able to store an agreed annual/monthly amount of CO2The tool will include probabilistic treatment of the unknown geological properties of storage sites.

Robust risk analysis tools for the operation of CO2 transport and storage networks will enable storage operators to decide the correct level of investment in site characterisation and infrastructure development and the most appropriate timing for the development.

Results from simulation of core flooding with six different foam-generating surfactants. Pure CO2 is displacing a solution of formation water and 0.5 weight-% surfactant. The plots show the situation after 0.4 pore volumes have been injected. Differences in CO2 solubility, adsorption and foam strength between the different surfactants lead to significant differences in the development of total surfactant concentration (including adsorbed surfactant) (left plot) and the mobility reduction effect (right plot). Characterisation of such differences are important when selecting an optimal surfactant for field application.

Results 2018

Main results

  • Laboratory testing of foam-generating properties of synthetized nanomaterials. Results for first batch mainly negative. Design directions for next batch discussed.
  • Synthetized next batch of nanomaterials for CO2/brine foam generation
  • Working version of MRST CO2-foam module. Simulations with Eclipse and with MRST presented in GHGT-14 publication. Demonstrate >100% increase in CO2 storage efficiency for five-spot CO2-injection/brine-extraction patterns.
  • Initial work to optimize cost/benefit for mobility control in CO2 storage.
  • Development of a storage site optimization work flow.
Demonstration of the effect of mobility control for CO2 in a five-spot well pattern. CO2 injected at a rate of 0.5 Mt/year through the well in the left corner into a 100-m thick reservoir section with horizontal dimensions 1400x1400 m, while brine is produced at the opposite corner. Top: After 6 years the CO2 has reached the location of the production well, and this section of the reservoir will have to be closed soon thereafter. Bottom: if mobility control can be implemented, the injected CO2 will move much more slowly across the reservoir section and will not reach the opposite corner until several years later, giving 50 % increased storage capacity in the shown example.

Results 2017

The mobility contrast between CO2 and oil/water, and the large well distance, make tertiary CO2 injection more challenging as an EOR option in the North Sea than in North America, where it is already being successfully employed.

The task investigates novel methods for controlling the mobility of injected CO2, such as functionalized nanomaterials for foam generation or direct CO2 thickeners.

Following a review of recent literature, the first series of newly designed POSS (polyhedral oligomeric silsequioxanes) nanomaterials was synthesized.

Testing of CO2 solubility and other properties will commence in 2018, to give input on further generations of nanomaterials. Mobility control of injected CO2 can also be beneficial for aquifer storage, since it could postpone the point in time when CO2 reaches spill points in structural traps. Initial modelling to investigate this effect has been performed.


Conference Publications


  • CO2 storage with mobility control - Grimstad, A.A., Bergmo, P., Møll Nilsen, H., Klemetsdal, Ø. GHGT-14, Melbourne

Task leader

Alv-Arne Grimstad

Senior Research Scientist
470 35 566
Alv-Arne Grimstad
Senior Research Scientist
470 35 566