Summary

The Alvheim Field, offshore Norway, has subsea wells with long horizontal branches completed with sand screens. After 10 years of production, water production starts to constrain the oil production. Mechanical water shutoff is not possible in these wells; hence, other methods are of interest. In a well workover in 2013, two high‐viscosity polymer pills were bullheaded and squeezed into the reservoir. The well productivity was reduced by approximately 50% and the water cut dropped, suggesting potentially higher oil recovery. A research study was started with the objectives of understanding the changed well performance and whether polymer bullheading can be a future method to reduce water production and enhance oil production.

An experimental laboratory program started with filtration tests of polymer solutions on the basis of the polymer used in the well operation. Coreflood experiments were performed by injecting polymer into two parallel‐mounted cores and then back producing these individually with either water or oil. Several combinations of parallel cores were tested with polymer injection: high vs. low permeability, high oil saturation vs. low oil saturation, outcrop sandstone vs. Alvheim core, and two different polymer formulations.

The polymer formulation as used in the well operation demonstrated the plugging of standard filters with filter size larger than the reservoir pore sizes, but it did not plug the cores. The polymer formulation as used in the well gave a better disproportionate permeability reduction (DPR) than the alternative polymer variant with similar viscosity. A theoretical model for the shear rate in the porous media matched the experimentally measured data excellently. The core results show a stable permeability‐reduction factor of 100 to 450 for water, while a factor of only 2 to 10 and decreasing with time for oil. The achieved DPR ratio of 45 to 80 is better than the trend from earlier published results.

The DPR as measured in the laboratory was next integrated into the reservoir model as part of the history match of the treated well. The Alvheim field has several reservoir zones separated with thin shales, and this reservoir zonation seems key for this enhanced‐oil‐recovery (EOR) method to work.

The laboratory work, the reservoir studies, and the field experience all point to a possible robust and simple EOR method for Alvheim and similar oil fields. Future work includes more research and maturing a new polymer pilot on Alvheim.

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