This paper presents field results from a number of scale squeeze treatments carried out on subsea and platform horizontal wells from a field in the North Sea (Nelson field). The evaluation of scale inhibitor chemicals from initial laboratory screening is reviewed along with significant factors which influence inhibitor selection when designing squeeze treatments for both horizontal and highly deviated wells. This includes discussion of formation brine/inhibitor incompatibility and formation minerals/inhibitor incompatibility. The potential for sand production and oil-in-water process upset which can result from the above factors is also discussed.

This paper outlines the practical difficulties in squeezing subsea horizontal wells and how some of these problems can be overcome. Some of the practical solutions discussed include the use of chemical stabiliser to reduce formation brine/inhibitor incompatibility, variation of pump rates to encourage propagation of inhibitor along the wellbore and the potential of fluid diversion (both mechanical and chemical). The significance of production logging data or good reservoir simulation data, to evaluate the location of water production prior to a squeeze treatment, is also stressed. This paper also presents details of divertor selection and the resulting squeeze design strategies that may be implemented.

From this series of field squeeze treatments it can be concluded that the wells have all been successfully treated, with minimal process upset during flowback, as a result of continuous design improvement based on the previous treatments. No long term decline in well productivity was observed as a result of these treatments. This paper clearly shows that with the correct laboratory evaluation process for both scale inhibitor and divertor agents and with utilisation of production logging and reservoir simulation data, it is possible to squeeze scale inhibitors into platform and subsea horizontal wells without the need for coiled tubing intervention.

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