Positive prospects for producing more

A very significant potential for enhanced oil recovery (EOR) on the Norwegian continental shelf (NCS) has been identified by a recent technical screening study of various EOR technologies.

Performed by experts from London’s Imperial College, this work addressed which EOR processes would be most suitable for the NCS and what incremental improvement could be achieved.

The study compared many different EOR processes with conditions in a number of Norwegian offshore reservoirs to determine how appropriate each of them would be for the respective formations.



The recovery factor or the proportion of oil originally in place extracted from fields on the NCS averages 47 per cent, which is high compared with average global figures of slightly less than 40 per cent. 

Various technologies can be deployed to enhance this recovery factor even further, and the following approaches have been used in or proposed for oil fields globally.

Gas injection.

  • The principal gases used are hydrocarbons, CO2 or nitrogen (or nitrogen-rich flue gas). Injected gas may be miscible – where the gas and oil dissolve in each other to create a more mobile fluid – or immiscible, with the oil and gas remaining separate phases.

    Both miscible and immiscible injection are usually implemented in alternation with slugs of water. Such water alternating gas (WAG) processes are more effective at producing oil, since the water improves gas sweep through the reservoir. 

    Hydrocarbon gas injection has already been used successfully on the NCS (in Statfjord and Oseberg, for example). CO2 injection has the added attraction that some of the gas will remain in the sub-surface permanently and thereby contribute to carbon capture and storage (CCS).

Alkaline flooding.

  • Alkaline substances added to injected water react with the oil to produce surfactant compounds which reduce interfacial tension with oil and alter wettability. Both these outcomes can mobilise more oil from the pore spaces.

Polymer flooding.

  • Water-soluble polymers added to injection water increase its viscosity and thereby improve water sweep through the reservoir.

Surfactant flooding.

  • Surfactant added to injected water alters the wetting state of the rock and reduces oil-water interfacial tension, thereby mobilising more oil from the pores.

Low salinity flooding.

  • Oil recovery during waterflooding can be improved by lowering the total salinity of injected water to less than 5 000 parts per million (ppm), and thereby making the rock more water-wet.

Surfactant/polymer and low-salinity/polymer flooding.

  • In these processes, surfactant or low-salinity flooding (which improves microscopic displacement efficiency) is augmented by adding polymer to improve injected water sweep.

Gels and thermally activated polymers (TAP).

  • These improve sweep by shutting off specific water flow paths close to producer or injection wells (gels), or deeper in the reservoir (TAP).

Each of these EOR processes has specific envelopes of conditions within which they will perform optimally, or outside which they will not work at all.

In the current study, 53 reservoirs and segments were evaluated in 27 fields, using such screening criteria as lithology, depth, pressure, temperature, oil API gravity, viscosity, oil acidity, oil wetting behaviour, and reservoir porosity and permeability.

Reservoir thickness, fracturing, heterogeneity, clay content, clay type, formation water salinity, injection water salinity, remaining oil and current recovery process were also taken into account.

These screening criteria cover a wider range than those used in other published studies, which thereby enhances the sensitivity of the method. Reservoir data contributed by field operators were screened using the criteria above with the aid of a specially constructed software toolkit.



Viable EOR processes were assigned recovery increments as a function of the generic effectiveness of the recovery process derived from global EOR project data, a suitability score and the field oil in place.

The suitability score quantifies the applicability of a given EOR process in a specified field. These scores were generated by the screening toolkit using the technical criteria, weighted for importance.

They vary between 0 and 1, where a score of zero means that the process is not viable and one means the process is optimal for that field. EOR processes with a zero score are assigned a zero recovery increment.

The EOR potential was estimated as the recovery increment for the top EOR process in each field – in other words, the one with the largest recovery increment.

When applied across all 27 fields studied, that gives an EOR potential of 592 million standard cubic metres (scm). This is the mid value in a range of possible outcomes based on an estimated technical potential of 320-860 million scm. The NCS clearly contains a very significant EOR potential (see figure).



Technical EOR potential 



Four EOR processes are widely applicable and have mid-case technical potential recovery increments of over 40 million scm.

  • Low salinity/polymer has the largest large potential increment, mainly from fields in the Utsira High and Tampen areas of the North Sea.
  • Surfactant/polymer suits similar fields, but only performs better than low salinity/polymer in a few fields from the Tampen area and the Halten Bank in the Norwegian Sea.
  • CO2 injection is promising in fields where CO2 is expected to be miscible at reservoir conditions. These are mainly the chalk fields in the southern part of the North Sea and fields in the Tampen area.
  • Hydrocarbon gas injection/WAG is potentially viable in many fields, and is already the most widely deployed EOR process in the North Sea.

Clear geographic trends for the applicability of EOR processes can be seen, and these could have important implications for economies of scale, for example by combining injectant supply (gas/chemicals) for multiple fields in the same area. The figure below shows three examples of such areas.


The figure below shows two areas where the same EOR method is the top opportunity for all the fields within them.


Other EOR processes (low salinity, gels, alkaline flooding) are viable for niche conditions in certain fields.

While low-salinity flooding, for example, is not as effective without added polymer, it is viable on fields which are either too hot for polymer deployment or have very low-viscosity oil where polymer would add no benefit.

Gels and thermally activated polymers are viable in very mature fields to improve sweep and control water production.



All the fields in the study have some EOR potential. The amount of incremental recovery for a specific field depends on two factors – first, the existence of an EOR process, which is fully optimal for that field with respect to its screening criteria and, second, the remaining field oil in place.

The amount of remaining oil, in turn, depends on the initial oil in place and the amount produced from the field so far.



This screening analysis gives an indication of the technical potential for EOR. The next steps are to apply rigorous operational, commercial and environmental screening criteria to determine more accurately the size and location of the practical potential.

The study recommends that the current work be followed up by a gap analysis to determine the main barriers to implementing EOR processes and an in-depth analysis of the most promising fields using a reservoir technical limits type of approach.

Further research may also be needed to develop some of these processes for the more testing conditions found in certain of these offshore fields, and to investigate the potential synergies between EOR processes and CCS.