The squeezing of scale inhibitors into the near well bore region of oil producing wells is a recognised solution to downhole scale prevention. In many cases, this downhole application leads to an initial decrease in the well productivity, which can recover to the pre squeeze level with time. However, in some reservoirs this recovery does not happen, and the well suffers a permanent loss in productivity after the squeeze.

Following such a loss in well productivity caused by an initial squeeze treatment, this paper details the development of a successful squeeze treatment for a water sensitive reservoir in the North Sea using an aqueous based sulphonated co-polymer scale inhibitor.

The paper summarises the additional core plug testing undertaken to evaluate the damage mechanism, the modifications made to the treatment design to minimise the damaging effects and culminates with the successful results from the application of the modified squeeze treatment. These results show that well stimulation and extended squeeze lifetime were achieved compared to the initial squeeze and to other previous applications of this inhibitor in similar water sensitive reservoirs.


The application of aqueous based scale inhibitor squeeze treatments is the most commonly used method of downhole scale prevention in the North Sea. Typical examples of these scale inhibitors are Phosphonates, Polyacrylates and Sulphonated co-Polymers. In the squeeze treatment, a slug of scale inhibitor is injected in the near wellbore formation followed by a displacing overflush. The overflush is typically injection quality seawater, although other displacement fluids have also been employed, e.g. diesel, nitrogen and live produced fluids. The squeeze fluids are then "shut in" to allow the squeeze inhibitor to adsorb or precipitate depending on the placement mechanism, before the well is brought back into production.

The application of the squeeze fluids can have significant detrimental effects on the well productivity. In these cases, the benefits derived from squeezing a well have to be offset against the potential losses in production. The loss in well productivity can be due to a number of factors. The pH of the scale inhibitor employed for example can have dramatic effects on the formation. Low pH inhibitors can cause dissolution of calcite cements within the formation leading to fines migration, plugging and/or sand production. A second factor is water sensitivity. This is the main focus of this paper. Here the hydrocarbon productivity of a formation is adversely affected by the presence of water in the squeeze treatment leading to detrimental relative permeability changes within the formation. The reduction in hydrocarbon production is usually combined with an increase in water production.

There are fields within the North Sea, which are particularly prone to the latter type of damage mechanism, especially at low water cut levels. The field referenced in this paper is the LASMO (TNS) Limited operated Birch field, which has a water sensitive reservoir.

The Birch field is located in block 16/12a in the UK sector of the North Sea approximately 155 miles North East of Aberdeen. The producing reservoir is the Jurassic Brae conglomerate. The development comprises three subsea production wells and two subsea injection wells, which are tied back to Marathon's Brae Alpha platform, some 12 km distant via a production/injection manifold arrangement as shown in Figure 1.

Scaling studies indicate that unacceptable levels of Barium Sulphate scaling would occur if standard seawater were used for pressure maintenance. The Birch formation waters have barium levels up to approximately 1000mg/L. Accordingly low sulphate seawater (LSSW) has been used for pressure maintenance augmented by scale squeeze treatments following water breakthrough.

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